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HomeMy WebLinkAboutIPCE958.docxSCOTT WOODBURY DEPUTY ATTORNEY GENERAL IDAHO PUBLIC UTILITIES COMMISSION PO BOX 83720 BOISE,  IDAHO  83720-0074 (208) 334-0320 Street Address for Express Mail: 472 W. WASHINGTON BOISE, IDAHO  83702-5983 Attorney for the Commission Staff BEFORE  THE  IDAHO  PUBLIC  UTILITIES  COMMISSION   IN THE MATTER OF IDAHO POWER) COMPANY’S 1995 ELECTRIC INTEGRATED)CASE  NO.  IPC-E-95-8 RESOURCE PLAN) )COMMENTS OF THE )COMMISSION STAFF __________________________________________) COMES  NOW  the Staff of the Idaho Public Utilities Commission, by and through its Attorney of Record, Scott Woodbury, Deputy Attorney General, and submits the following  comments for the Commission’s consideration in Case No. IPC-E-95-8. Staff  has reviewed the 1995 Integrated Resource Management Plan (IRP) filed by Idaho Power Company (IPC), and finds that it satisfies the requirements set forth by the Commission in Order No. 22299.  Staff recommends that the Company’s IRP be accepted for filing.  Staff comments and concerns are noted below. General Comments IPC’s IRP is well presented and mechanically sound.  They have access to and use state of the art tools and technology for gathering and analyzing their data.  The IRP is also intellectually rigorous.  In addition to substantial histories of electrical usage and time and season load shapes, they contract with Wharton Econometrics and other  acknowledged leaders in the forecasting industry.  This gives them access to the best minds in the area of economic forecasting.  It also provides a reference point to assure that their estimates for the future are consistent with national thinking. Demand/Load Forecast One concern with the Company’s forecast is with timing.  A handful of potentially significant events have occurred since IPC made the forecast used for this IRP.  These are, the unforeseen layoffs at HP, restructuring (more layoffs) because of the West One merger, the retrenchment at Micron Technology as a result of depressed chip prices, and the problems at Morrison Knudsen.  Admittedly these are primarily western Idaho impacts.  However, this is a significant part of IPCs territory and as a result it wouldn't be surprising to see a tempering of forecast rates of growth for population and electricity demand in future forecasts. IPC sources many of the variables in the forecast from subscription services such as Wharton, Moodys and others.  Qualitatively, there is nothing wrong with these as sources.  However, these are sources to which the general public, and indeed the Commission, does not have ready access.  To the extent that IPC’s IRP will be used to set avoided cost rates for PURPA contracts, etc., and needs to be open to review, it would be well if IPC provided some mechanism by which the Commission and the general public could gain access to the same data sources as updates are acquired. For 1995, IPCs Base Case load forecast is quite similar to the forecast in the 1993 plan.  The main difference is that the 1995 plan starts slightly higher and finishes slightly lower. Total Energy Load Forecast (Average Megawatts) 1992199520002005201020142015 Base Case 1993159917441782187620342194 Base Case 199517631826190520312188 To meet the forecast total load growth, resource additions totaling 360 average megawatts are included in the 20 year plan.  These additions are expected to be accomplished in a variety of ways, such as, 30% (107 aMWh) from a combination of committed Qfs, committed conservation, hydro upgrades, and efficiency improvements, 14% (51 aMWh) from market purchases, and 56% (202 aMWh) from thermal resources. At this point, the 51 aMWh of capacity that IPC intends to acquire through market purchases may be the most speculative part of this IRP.  A variety of factors, including the degree to which deregulation occurs, and how soon, as well as the degree to which other utilities attempt to utilize market purchases, will have a profound impact on the desirability of this action.  Open market purchases of firm power on a large scale is still a new and developing concept.  As of this writing, futures trading in firm electricity at the California-Oregon border has been occurring for less than three weeks and does not extend past six months into the future.  As such, the long term price and availability of open market is tantalizing but almost completely unknown.  Hopefully, it will be possible to develop this subject more fully before the next IRP, or before open market purchases are required to meet demand, whichever comes first. There is also some uncertainty regarding the 202 aMWh that IPC intends to obtain from thermal generated resources.  This is generally thought to mean gas fired combined cycle turbines (CC in IPC’ IRP) but the words coal-fired do appear in this context briefly at the end of the introduction and in a few scattered references throughout the rest of the report.  The most significant of mention is in the section titled 20-Year Resource Plans for the Preferred Near Term Acquisition Plan.  Section two states (emphasis added), Gas-fired combined cycle turbines are selected as the most cost effective resource type for the next resource additions in the case of low gas prices, while PFB coal-fired generation is projected to be most cost effective on the Idaho Power system under the base or high gas price forecasts.  Advances in both technologies should therefore be monitored. In short, with the base gas price forecast and the base load growth forecast, the resource of choice in 2014, (1998 under the high load growth forecast) is coal fired generation.   The gas price forecast controls whether gas or coal is the fuel of choice.  IPC is forecasting that gas prices will increase at between 4.2% and 6.25%, nearly twice the rate of either general inflation or electricity prices.  This forecast is derived from a variety of sources that include; The American Gas Association (AGA), Bonneville Power Administration (BPA), Gas Research Institute (GRI), Intermountain Gas Company (IGI/IGC), Northwest Power Planning Council (NWPPC), and Wharton Econometric (WEFA).  A price escalation of 6.25% means that gas prices will double every 11 years.  While it would seem hazardous to dispute such an esteemed collection of authorities, one would do well to remember that general inflation as measured by the consumer price index has out paced gas prices since at least 1970.  It may be that a correction in gas prices is due, or even overdue, however sustained price inflation of gas relative to other energy sources as presented here is unheralded in recent history.  Also, perhaps most significantly, gas futures, as reported in the most recent Wall Street Journal, show little or no inflation through December of 1998, the end of the trading horizon. Perhaps the most that can be definitively stated at this time is that, in IPC’s words, advances in both technologies should therefore be monitored.  However, one should remember that the decision as to the choice of fuel may be the least of the problem.  Past history has shown that siting a coal fired plant can be a difficult, contentious, lengthy process.  Future IRP related proceedings would do well to provide more detail on this subject. In the IRP summary, Hydro relicensing is mentioned only once, and then only in the context of the Shoshone Falls project.  The bigger issue of the relicensing of IPC’s other facilities is quickly approaching and is an issue with tremendous consequence for both IPC and Idaho.  The issues are still poorly defined, but that is beginning to change as the various factions begin to detail their positions.  Staff expects this to be a substantial issue in following IRPs. Demand Side Management The plan submitted by IPC addresses all of the items required by the Commission in Order No. 22299.  The discussion addresses all of the issues and sectors identified by the Commission, and when considered in the context of the constraints imposed by the economic assumptions and policies identified by the Company, it identifies a reasonable selection of resources to meet the expected demand. The Demand Side Management (DSM) activities identified in the Company’s IRP, as well as the 1995 Conservation Plan, cannot be considered as “aggressively addressing” the issue of demand side resources in a manner that the Commission indicated it would reward in Order No. 22299.  The Company’s plans show expenditures for conservation declining rapidly, from nearly $5 million in 1995, to under $3 million in 97-98, and only $239 thousand in 2004 and beyond. The decline in expenditures is primarily related to a policy decision by Idaho Power to increase the portion of total resource costs that are paid by the customer, and decrease the portion paid by the utility.  By increasing the costs of participation for the customer, the Company is decreasing the penetration rate of the programs, and reducing the amount of DSM resources that will be purchased. When the Commission approved the Demand Side Tariff Rider for Washington Water Power, it approved an activity level for DSM activities that was equal to 1.5% of gross revenues, a rate that was approximately equal to the national average for utility DSM expenditures in the early 1990's.  Under Idaho Power’s Plan, DSM activity, which was at slightly less than 1% of revenues in 1995, will fall rapidly to less than one half of one percent of revenues by 1997, and to less than a tenth of one percent by 2004. Idaho Power has expressed some interest in implementing a tariff rider or similar alternative to traditional financing for DSM measures.  Staff is concerned with the level of DSM purchases that are proposed by the Company, yet recognizes the Company’s concerns with competition.  If the level of DSM purchases were not decreasing, Staff would look more favorably at such alternative methods of financing these purchases. Staff provided the Company with a number of comments on the DSM components of a draft version of this plan, and, with the exception of the minor typographical suggestions, the concerns raised in those comments remain pertinent to the Plan submitted for filing. Those concerns included questions on the generally low levels of incentive the Company intended to provide, a concern about the use of the Total Resource Cost test as the sole basis for including a resource in their screening process, and a general concern that the differences between the options considered were so small that they exceeded the precision of the analysis methodology.  With many of the parameters used as input to the process, such as penetration rates for conservation programs, barely more than educated guesses, deciding between two options that have identical costs for the first five digits is stretching the capabilities of the mathematical calculations. Staff believes that the role and format of the Integrated Resource Plan, as well as the Conservation Plan, may need to be examined in light of the changes that are occurring within the electric industry.  These documents served a valuable purpose in the regulatory climate in which they were initially required, but as that environment changes, the requirements for these documents may need to change as well.  Idaho Power, and the other utilities in the State have already begun the initial discussions and analyses for the IRP’s that will be submitted in 1997.  Staff recommends that the role of IRP’s be addressed by the Commission, in the electric restructuring case, GNR-E-96-1. Competition and Power Markets Throughout its IRP, Idaho Power points out that competition is evolving in the electric industry and that the Company is preparing for it.  Staff agrees that the utility structure is changing, and that utilities must adapt in order to remain competitive.  Staff sees the role of integrated resource planning changing significantly in the future as the industry changes.  New resource acquisitions in the future will no longer consist primarily of Company-owned generation or Company-sponsored conservation.  New resources will likely include a much wider variety of choices.  Flexibility and the ability to quickly adapt to changes will become more important.  Risk management tools will become more valuable. While the Company has begun to change its planning process, Staff believes the process must further adapt to be effectively utilized under new utility environments.  Staff believes the Commission’s integrated resource planning requirements are flexible, and fully expects future IRPs to be different than the current one.  The future focus of planning may shift and the methods may change, but Staff does not believe the need for resource planning will diminish in the future.  Staff expects the Company to work to develop new planning tools and methods. Capacity Reserve Prior to the 1995 IRP, Idaho Power’s capacity reserve consisted of a six percent planning reserve and a six percent operating reserve.  The six percent operating reserve has been retained, but the planning reserve has been reduced from six percent to zero.  Thus, the total reserve has been reduced from twelve to six percent.  Staff does not disagree with the Company’s decision, but believes it will be extremely important to carefully monitor the available reserves in the future to insure that reliability is maintained and that customers are not jeopardized needlessly by the Company being forced to acquire very high priced resources to meet deficits.  While Staff recognizes that a substantial reserve is available in the WSCC, Staff is also aware that the reserve has been decreasing and is expected to decline further as other utilities reduce their planning margins as Idaho Power is doing.  Staff also recognizes that most new resource options have shorter lead times, thus reducing the risks if load growth exceeds expectations. Staff recommends that the Company be required to periodically submit to the Commission information needed to track monthly capacity and energy reserve margins. Shoshone Falls In updates to the 1995 IRP received on March 15, 1996, the Company states that it has decided not to pursue a capacity expansion at Shoshone Falls.  In the IRP, the Shoshone Falls project was estimated to have a nominal levelized 30-year cost of 31.35 mills/kWh.  At this cost, the Shoshone Falls project is the least expensive supply side option, except for system upgrades and efficiency improvements.  In addition, the portfolio of resource options that includes Shoshone Falls is the least cost mix of resources according to the Company’s decision tree analysis. Since the expansion would have to be requested in the relicensing application which is due to FERC in 1997, the expansion project could be considered a lost opportunity if not pursued now.  Staff does not necessarily believe that foregoing the expansion is a mistake.  However, Staff does wish to point out that by foregoing the project, the Company is setting a new benchmark for cost effectiveness.  Recent market purchases made by the Company have been at a cost lower than the estimated levelized cost of a Shoshone Falls expansion.  However, a direct comparison of cost effectiveness is difficult since Shoshone Falls is a long-term resource and market purchases are usually only a few years in length. Market purchases that exceed the estimated cost of Shoshone Falls should be scrutinized carefully by the Commission. Selection of Variables Used in Avoided Cost Calculations Staff has reviewed the variables included in the IRP which are used in the calculation of avoided costs.  Staff believes all of these variables are within a reasonable range. Hydro Relicensing In its IRP, the Company has assumed that all existing hydro facilities will be relicensed, yet no assumptions have been made about the cost of relicensing.  The Company has considered relicensing costs indirectly, but only in terms of a reduction in peak generating capacity.  Admittedly, the costs of relicensing are still unknown.  However, as the Company proceeds to relicense some of its facilities and as the true costs of relicensing become known, these should be considered in future analysis of new resource options. Company-Owned vs.  Independently-Owned Resources Since the IRP serves as an evaluation of all resource options, without regard to whether the resource would be Company-owned or independently-owned, Staff wishes to reiterate that in resource acquisition, Company-owned resources should be held to the same cost effectiveness criteria as independently-owned resources. Updates to the 1995 Integrated Resource Plan In the March 1996 updates to the IRP, Staff discovered numerous errors in the presentation of the changes.  Although the Company has since corrected the errors and provided revised information to Staff, Staff believes the Company should also provide revised information to all parties in the case. DATED  at Boise, Idaho, this            day of April 1996. ______________________________________ Scott Woodbury Deputy Attorney General _______________________________________ Tony Jones Staff Economist _______________________________________ Rick Sterling Staff Engineer _______________________________________ Wayne Hart Consumer Assistance Investigator SW:umisc\comments\ipce958.sw