20011019Notice of Application.doc

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

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

Attorney for the Commission Staff

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE FILING BY PACIFICORP DBA UTAH POWER & LIGHT COMPANY OF ITS 2001 ELECTRIC INTEGRATED RESOURCE PLAN (IRP). )
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CASE NO. PAC-E-01-13

COMMENTS OF THE COMMISSION STAFF

COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its Attorney of record, Scott Woodbury, Deputy Attorney General, and in response to the Notice of Filing and Notice of Comment Deadline issued on August 22, 2001 submits the following comments.
On July 5, 2001, PacifiCorp dba Utah Power & Light Company (PacifiCorp; PCP; Company) filed its 2001 Resource and Market Planning Program (RAMPP-6; IRP) with the Idaho Public Utilities Commission (Commission). The Company’s filing is pursuant to a biennial requirement established in Commission Order No. 22299, Case No. U-1500-165. The IRP describes the Company’s loads and resources, provides an overview of technically available resource options including conservation and establishes a demonstrated need for resources in 2004. PacifiCorp’s filing includes a model output appendix and an addendum to the report entitled “RAMPP-6 Special Studies.”
Changes Since the Previous IRP
PacifiCorp’s previous IRP, RAMPP-5, was filed with the Commission in 1997. Since that time, there have been several significant changes that have affected the Company’s planning. Market prices for gas and electricity, of course, have been one of the most noticeable. However, the volatility in these prices was unforeseen at the time the analysis for RAMPP-6 was conducted. Consequently, the range of gas and market prices considered in the IRP was too narrow to capture the unprecedented prices recently experienced. However, even within the range of prices analyzed, the Company has identified the prices at which coal-fired resources are preferred over gas-fired resources. In addition, the Company conducted several special studies that are included as an addendum to the RAMPP-6 report examining the effects of high gas and electric market prices.
Other changes since the previous IRP have been increasing demands from some customers for improved reliability, the emergence of distributed generation, and piecemeal restructuring in some of the states in which PacifiCorp provides service. In addition, because the majority of PacifiCorp’s generation is fueled by coal, there is increasing possibility that environmental mitigation measures will be required that could increase coal plant costs or require old plants to be retired early. Finally, the Company is actively relicensing 13 hydro projects totaling 993 MW of existing generation throughout its service territory. New licenses generally contain terms and conditions that involve significant capital expenditures and result in lost generation as a result of changes in operation.

Load Forecast
PacifiCorp’s load forecast projects an overall annual growth rate over the 20-year planning horizon of 2.6 percent. The Company includes forecasts for average annual energy and both summer and winter peak loads.
Because open access is already available in California and is scheduled to begin soon in Oregon, PacifiCorp believes there is a possibility that it could lose a substantial portion of its regulated load. This caused some problems for the Company in preparing its load forecast. For the purposes of the IRP, a decision was made by the RAMPP Advisory Group to assume that all regulated load should be included over the planning horizon.

Reserve Margins
Reserve margins are set in RAMPP-6 to be not less than ten percent. This is the same reserve margin used in developing previous IRPs. The Company assumes median water conditions for its hydro plants, but has also explicitly considered the effects of critical water in one scenario examined. For PacifiCorp, the difference between critical water and average water is 171 aMW. The planning model responds to reduced hydro generation in the early years of the study by reducing short-term sales and increasing short-term purchases. In 2004, the model selects additional gas-fired resources to replace lost generation. While the effect of critical water on the Company is not insignificant, it is much less critical for PacifiCorp than for Idaho Power or Avista because such a small percentage of the Company’s generation is hydro.

PacifiCorp’s Planning Approach
The approach taken by PacifiCorp in this IRP was significantly different than in the past. Previously, the Company made a forecast of what it expected gas and market prices to be over the planning horizon. However, in this IRP, PacifiCorp simply chose to analyze what it believed was a reasonable range of gas and market prices. Over 100 different scenarios were analyzed for this IRP. Besides two reference cases, the Company studied 48 cases in which gas and market prices were varied, 30 cases in which various levels of load losses were assumed, 12 cases to consider possible environmental adders, and 12 special interest cases. In addition, several “special studies” were completed as requested by the RAMPP Advisory Group. By studying the results of many different gas and market price scenarios, breakpoints could be identified indicating when significantly different new resource choices would be made. For example, new gas-fired generation is the resource of choice if gas prices are below approximately $2.80/MMBtu. Above this price however, coal-fired generation is more economical if no environmental adders are assumed.
Had PacifiCorp known that natural gas and electric market prices would rise to unprecedented levels, it could have greatly expanded the range of prices examined in the IRP, thus producing results more indicative of the scope of possible outcomes. No one expected such high prices however, and once such high prices became evident, work in finalizing the IRP was well on its way toward completion. Performing additional analysis to incorporate much higher gas and market prices would have required great effort and resulted in a lengthy delay in filing the final document. As an alternative, the Company conducted several “special studies” which it included as an addendum to the RAMPP-6 report.
For comparison purposes, PacifiCorp did identify a reference or “base” case. The reference case however did not necessarily reflect what the Company believed would be most likely to occur. However, a “weighted average reference case” was identified that represented the overall results if all of the cases examined were weighted based on PacifiCorp’s belief of the likelihood each would occur.

Reference Case Results
The reference case assumes gas prices start at $1.90 per MMBtu, that there is high gas and market price escalation and that the wholesale market price starts at 26 mills/kWh. The gas price escalates at 0.6% real or 3.4% nominal per year. Wholesale market prices escalate at 0.36% real or 3.16% nominal per year.
As in RAMPP-4 and RAMPP-5, gas-fired resources are the least cost alternative for new generation. Cogeneration and combined cycle combustion turbines (CCCT) have very similar total system costs and are selected first by the planning model, beginning in 2004. Prior to 2004 when new generation can be brought online, short-term capacity purchases are selected in amounts up to about 100 aMW. New generating resources are selected in the Oregon-Washington area first because the area is resource deficit and because gas-fired resources can be sited at a lower altitude, which allows for higher gas resource efficiency. Coal-fired resources do not become economical until 2020 in the reference case. A small amount of wind resources also are selected in 2020, but no other renewables are chosen. The planning model preferred gas-fired over coal-fired resources and pulverized coal over integrated gas combined cycle coal units (IGCC). These units represent new coal plant technology and convert coal to gas and burn the gas in a combined cycle CT. Their advantage is 30% lower NOx emissions, but their disadvantage is 10-15 percent higher costs.

Weighted Average Reference Case
The most striking result from the weighted average reference case is that it differs only slightly from the reference case. A comparison between the incremental summer capacity resources in the reference case and the weighted average case demonstrates that within the range of sensitivities incorporated in the weighted average case, the model chooses comparable amounts of short-term capacity purchases in the first three years and gas-fired cogeneration and combined cycle CTs starting in 2004. Based on this result, PacifiCorp concludes that development of new resources is warranted in the next three to five years. The Company notes that analysis in currently ongoing to evaluate the potential need to accelerate the development of new resources due to recent high market prices and potential shortage of available capacity.

Risk Analysis
PacifiCorp performed extensive risk analysis in this IRP. In its initial studies, the risks examined were variations in natural gas and electric market prices, loss of significant load, higher costs of generation due to environmental adders, and several special interest cases.
In order to develop a better understanding of the risks that the Company faces as a result of various gas price and wholesale market price combinations, gas prices were assumed to vary from a minimum starting price of $1.30/MMBtu to a maximum starting price of $2.80/MMBtu, with nominal gas escalation rates varying from 0.8% to 3.8%. This produced a broad range of twelve forecasts that blanketed the range from $1.30/MMBtu to $3.60/MMBtu over the planning horizon. A range of wholesale electric market prices was also assumed. Market prices from 22 to 34 mills were considered, with nominal escalation rates varying from 1.6% to 3.4%. It should be noted however, that these gas and market prices were established in May of 2000. At that time it was thought that they encompassed any potential future price range. Although gas and market prices have now returned to these ranges, they greatly exceeded these levels for most of the past year.
The most important result from the gas and market price risk analysis is that gas-fired generation is the resource of choice if natural gas prices remain relatively low. At gas prices of $1.90/MMBtu, combined cycle combustion turbines can be developed for about 24 mills/kWh. Coal-fired plants can be developed for about 31 mills/kWh. RAMPP-6 determined that gas-fired resources are economical up to gas prices of $2.80/MMBtu and that coal-fired resources are more economical thereafter.
PacifiCorp’s load loss risk analysis was intended to assess the impact of substantial load losses as the industry transitions from a regulated to a more deregulated environment. In Oregon, as a result of SB1149, the Company believes it is possible that between 32 percent and 50 percent of its load could eventually be lost. In Utah, the potential loss of the Company’s major industrial customers was examined. The results of this analysis, as expected, are substantial increases in reserve margin that only gradually return to a ten percent level as other load growth increases enough to consume the excess generation.
Various levels of environmental adders were also examined to determine their effect on generation alternatives. Inclusion of an environmental adder has two principal effects. At low adder levels, the planning model responds by operating the system differently, but not changing the overall mix of generation. At higher adder levels, the model will replace existing coal-fired generation with gas-fired resources, wind and geothermal. PacifiCorp does not believe that very high environmental adders are likely, however.
Primarily because gas and electric market prices rose to such high levels following the time when final model input assumptions were fixed for preparation of the final IRP document, the RAMPP-6 Advisory Group requested that the Company make several additional model runs using much higher gas and market prices. The results of these runs were included as an addendum to RAMPP-6 and are titled RAMPP-6 Special Studies. The results of this analysis are not unexpected—the planning model selects more and more coal-fired generation as gas prices increase—but the analysis does serve to confirm the location and timing for new resource development.

RAMPP-6 Action Plan
The RAMPP-6 Action plan focuses on three key issues. First, the plan sets a new target for the amount of DSM to be pursued. The reference case chooses 16.5 aMW in 2001 and 16.1 aMW in 2001. These targets are slightly higher than those in the previous IRP, reflecting the higher market and gas prices and the further proximity between increased load and availability of new generation. As in previous RAMPPs, the Company based its DSM targets on DSM costs that are 15 percent lower than costs the Company actually incurs. The 15 percent reduction reflects the 10 percent Northwest Power Act credit and an additional 5 percent for avoided investment in transmission and distribution.
Second, the Action Plan identifies the amount and year in which new generation will be required. The reference case indicates a need for 540 MW of summer capacity in 2004. The weighted-average risk analysis indicates a need for 364 MW at that same time. The Company will be monitoring closely the developments in the western power market during 2001 in order to make an informed decision as to how this requirement will be met. If the Company proceeds to develop new resources for the 2004 time frame and a loss of load materializes, the Company will be in a position with an 18.2 percent reserve. This reserve margin is significantly higher than that required to provide safe, reliable service.
The Company believes that it must carefully weigh the impacts on customers and shareholders before it can commit to a specific new generation strategy. Resolution of the Oregon restructuring plan, the Company’s proposed reorganization, consideration of potential changes in the California market and restructuring efforts within PacifiCorp’s service territory will all be considered.
Specific actions that are under consideration in 2001 and 2002 include the addition of single cycle turbines at the Gadsby site in Salt Lake City and at West Valley City in Utah to meet near term capacity needs. The Company is also considering building a fourth coal-fired unit at the Hunter site in Utah. The consideration of a coal unit is an example of the use of risk analysis in planning. RAMPP-6 indicates that natural gas fired units are lowest cost, however, that conclusion is based on natural gas price ranges that are lower than those recently experienced in the market. If gas returns to its recent high prices, coal becomes more economical. Weighed against gas prices in the decision process is the potential for further emission controls that would impact the costs of a coal-fired facility.

STAFF RECOMMENDATION
Staff recommends that the Commission acknowledge PacifiCorp’s RAMPP-6 integrated resource plan. Despite the plan’s minimal ability to analyze circumstances that encompass the wide range of gas and market prices experienced during the past year, the plan nevertheless provides valuable insight into the Company’s need for new resources, the alternatives likely to be pursued, and the risks associated with various alternatives.
At the time the analysis for the IRP was completed, it did reflect what the RAMPP-6 Advisory Group believed was a reasonable range of gas and market prices. The extensive analysis conducted by PacifiCorp and the period of time required to complete it unfortunately did not allow the wide variations in gas and market price to be considered. The Company’s suggestion that it conduct ongoing analysis and provide periodic updates to the various state commissions is a reasonable solution to the problem of the IRP preparation cycle being too long to quickly consider changes in conditions.
Staff’s only real criticism of the IRP is that it does not appear to fully reflect the plans the Company intends to pursue. To its credit, the Company has made a huge effort to analyze and document various scenarios. However, few, if any of the scenarios analyzed identify simple cycle combustion turbines to be located in the Salt Lake area and the addition of a fourth unit at Hunter as the preferred alternatives. In fact, in the near term the Company’s planning model selects short-term capacity purchases instead of simple cycle combustion turbines. The deviation between the IRP and actual Company plans is understandable given recent events, but still, the IRP offers little support for these short-term activities. This makes the report somewhat confusing to readers and confirms that the report is of limited value in light of recent changes in the electric industry. Staff believes that the lessons learned during the past year will be incorporated into the Company’s next IRP.

Respectively submitted this day of October 2001.

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Scott Woodbury
Deputy Attorney General

Technical Staff: Rick Sterling

SW:RPS:i:umisc/comments/pace01.13swrps

STAFF COMMENTS 3 OCTOBER 19, 2001