Loading...
HomeMy WebLinkAbouthessing.pdf 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Q. Please state your name and business address for the record. A. My name is Keith D. Hessing and my business address is 472 West Washington Street, Boise, Idaho. Q. By whom are you employed and in what capacity? A. I am employed by the Idaho Public Utilities Commission as a Public Utilities Engineer. Q. What is your educational and experience background? A. I am a Registered Professional Engineer in the State of Idaho. I received a Bachelor of Science Degree in Civil Engineering from the University of Idaho in 1974. Since then, I have worked six years with the Idaho Department of Water Resources and two years with Morrison-Knudsen. I have been continuously employed at the Commission since August 1983. As a member of the Commission Staff, my primary areas of responsibility have been electric utility power supply, revenue allocation and rate design. I have worked with Idaho Power’s (Company) Power Cost Adjustment (PCA) mechanism since 1992 when the formative case was filed. Q. What is the purpose of your testimony in this proceeding? A. My testimony addresses the calculation of the IPC-E-02-2/IPC-E-02-3 HESSING, K (Di) 1 04/22/02 Staff 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 PCA forecast and true-up, alternatives for recovery of this year’s PCA costs, the design of rates, except residential rates, and a Demand Side Management (DSM) rate rider. Q. Please summarize your testimony. A. I determine that the Company’s calculation of the coming year’s power supply forecast cost is done according to the Commission-approved methodology. I incorporate four adjustments proposed by Staff witness Holm into the true-up calculation. These adjustments reduce the true-up amount to be recovered from ratepayers by approximately $16 million. I review four alternatives, including the Company’s three-year securitization proposal, for spreading this year’s PCA costs over one or more years. I recommend a two-year recovery period with no securitization. My proposal reduces customer rates by an average of 9.6 percent in the coming PCA year. I recommend that PCA rate reductions be incorporated in all customer rates on an equal cents per kilowatt-hour basis except residential customer rates. Staff witness Schunke addresses the rate design for the residential class. I propose that a Demand Side Management (DSM) rate be added to all customer rates to fund additional DSM program costs. Q. How do you view the two cases filed by Idaho IPC-E-02-2/IPC-E-02-3 HESSING, K (Di) 2 04/22/02 Staff 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Power that the Commission is reviewing in this proceeding? A. I view the consolidated case as Idaho Power Company’s 2002 Power Cost Adjustment (PCA) rate filing. The filing proposes a mechanism to recover PCA costs by adjusting customer rates. The Company’s proposal seeks to recover PCA costs using a combination of a PCA rate and a securitized rate. PCA DESCRIPTION AND HISTORY Q. Please describe in general Idaho Power Company’s Power Cost Adjustment Mechanism. A. Idaho Power’s PCA is a rate adjustment mechanism that annually increases or decreases customer rates to reimburse the Company for above normal or below normal costs of supplying power. Traditional power supply costs are fuel costs and purchased power costs offset by sales revenues from the sale of surplus energy. The two major factors that affect power supply costs are Snake River drainage water supply conditions and Northwest wholesale power market prices. Good water conditions decrease Idaho Power’s power supply costs and return money to customers through reduced rates. Poor water conditions increase power supply costs, which are recovered from customers through increased rates. Q. Traditionally, what have been the major IPC-E-02-2/IPC-E-02-3 HESSING, K (Di) 3 04/22/02 Staff 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 components of the PCA? A. Each year’s PCA has traditionally been composed of a forecast or projection of costs for the coming year, a true-up to actual costs of the previous year’s forecast and a calculation of the PCA rate. Each year’s forecasted PCA costs rely on the National Weather Service’s River Basin forecast Center April 1 forecast of April through July Brownlee Reservoir inflow volumes. The estimated inflow volume is used in a mathematical formula that relates inflow to Idaho Power’s power supply costs. Only 90 percent of the above or below normal forecasted power supply costs are allowed to be recovered from customers in the PCA. Each year the previous year’s forecasted power supply costs are trued-up to actual power supply costs. Ninety percent of the difference from normal goes into the PCA. The other 10 percent of these costs are absorbed by Idaho Power Company’s shareholders. Finally, the PCA rate is calculated. The dollar amount of the combined forecast and true-up is divided by the number of kilowatt-hours (kWh) the Company sells in a year. Customer rates are adjusted by this ¢/kWh amount, which may either increase or decrease customer rates. Staff Exhibit No. 102 shows the history of all PCA rate adjustments since the first PCA rate IPC-E-02-2/IPC-E-02-3 HESSING, K (Di) 4 04/22/02 Staff 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 adjustment was instituted in 1992. The 2002 PCA amount of $253.8 million is the amount I calculate, including Staff adjustments, for the 2002 PCA year. In all PCA years through 2001, the PCA amount has been recovered from or credited to ratepayers in a single year. Some of the options in this case would spread the recovery over two or more years. THE PCA FORECAST Q. What is the Company’s proposed PCA forecast? A. The Company proposes that the PCA forecast rate be .2156 ¢/kWh. The rate is based on Brownlee inflows of 3.63 million acre-feet in the April through July period this year. The Brownlee inflow forecast of 3.63 million acre-feet is only 58 percent of normal. Last winter’s precipitation was well above 58 percent of normal. However, there are several large reservoirs above Brownlee Reservoir on the Snake River. Due to last year’s drought, these upstream reservoirs are low and will require more of the available water than normal in the April through July period. Therefore, the forecast predicts only 58 percent of normal Brownlee inflow during the April through July period. Q. Do you agree with the Company’s calculation of the forecast rate? A. Yes I do. I have checked the April through IPC-E-02-2/IPC-E-02-3 HESSING, K (Di) 5 04/22/02 Staff 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 July Brownlee inflow estimate and verified that the Commission-approved methodology has been correctly applied. Staff Exhibit No. 103 graphically represents the computation of forecast PCA expense, which is later used to calculate the forecast portion of the PCA rate. I expect the proposed forecast rate to recover approximately $27.5 million dollars during the PCA year. THE PCA TRUE-UP Q. What does the Company calculate the true-up for 2001-2002 to be? A. The Company’s true-up calculation to last year’s forecast, after jurisdictional allocation and sharing between ratepayers and shareholders, indicates that Idaho ratepayers are responsible for approximately $223 million in unrecovered power supply costs and miscellaneous items accorded PCA treatment. (Company Exhibit No. 3) The true-up calculations contain irrigation and Astaris load reduction costs, which replaced market purchases, and some other new items approved by the Commission for PCA treatment. Staff witness Holm further discusses some of the components in the true-up calculation. Q. Does the Staff agree with the Company’s true-up calculation? A. Staff witness Holm proposes four changes to the IPC-E-02-2/IPC-E-02-3 HESSING, K (Di) 6 04/22/02 Staff 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Company’s true-up calculation. He proposes that lost revenue be removed from irrigation load reduction program costs, that an adjustment be made to mobile generation costs and that two adjustments be made to the operating costs of Idaho Power’s Mountain Home Combustion Turbine. These adjustments to the Company’s true-up calculation are shown on Staff Exhibit No. 104, pages 1 and 2. Page 1 shows March through October 2001 and page 2 shows November 2001 through March 2002. The Staff adjustments are in bold and shown on lines 14, 17 and 21. They are all reductions to the Company’s actual PCA expense. Q. What is the amount of the true-up recommended by Staff? A. The Staff adjustments to the true-up calculation previously discussed reduce the amount of the true-up from $223 million proposed by the Company to approximately $207 million. PCA COST RECOVERY OTIONS Q. How does Idaho Power propose to recover this year’s PCA cost? A. Idaho Power proposes that part of the cost of last year’s true-up and the unrecovered portion of last year’s October PCA rate adjustment be spread over three years. Idaho Power proposes to sell bonds and adjust customer rates each year to ensure that the bonds are IPC-E-02-2/IPC-E-02-3 HESSING, K (Di) 7 04/22/02 Staff 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 retired in three years. This bonding process is called securitization. The securitized rates would also recover bond interest and the cost of bonding. The remaining unsecuritized portion of the true-up and the forecast would be recovered using a normal PCA rate adjustment over a one-year period. Under the Company’s proposal, this year’s PCA rates would have a PCA component and a securitization component. The Company’s proposal offers customers an average 6.6 percent decrease from existing rates in the coming PCA year. The Company proposes to securitize $172 million. This amount is composed of $147 million in true-up costs, $18 million in unrecovered October 2001 PCA costs and $7 million in bonding costs. Bond interest is in addition to the $172 million. As previously mentioned, the securitization rate paid by customers also includes bond interest, which can be estimated but is not known until the bonds are sold. The one-year PCA rate is composed of the remaining true-up amount of approximately $76 million and the forecast amount of $28.5 million. Under the Company’s proposal, PCA rates would also decrease at the beginning of the second and third PCA years, returning to base levels at the beginning of the fourth year. Securitization causes additional IPC-E-02-2/IPC-E-02-3 HESSING, K (Di) 8 04/22/02 Staff 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 interest and bonding costs. Q. Have you reviewed additional options for the recovery of this year’s PCA costs? A. Yes. I have examined four options. Option No. 1 is the Company’s securitization proposal with Staff’s adjusted true-up. None of the other three options include securitization. Option No. 2 recovers all of the PCA costs in the first PCA year, which requires an increase above existing rates. Option No. 3 continues the existing rates in the first PCA year and carries the unrecovered costs over to the 2003 PCA year with interest. Option No. 4 reduces rates in the first year by an average amount of 9.6 percent, 7.8% for Residential customers, and carries the unrecovered amount into the 2003 PCA year for recovery. The four options are compared in Staff Exhibit No. 105. Q. Please describe Staff Exhibit No. 105. A. Staff Exhibit No. 105 identifies each of the four options across the top of the columns. The cost recovery proposed for each option is broken down by year in the top three sections on the page. Each year identifies costs to be recovered in that year under the traditional “PCA” mechanism and with “Securitization”. The bottom section on the page totals the recovery over the three years identified. The bottom line on the page IPC-E-02-2/IPC-E-02-3 HESSING, K (Di) 9 04/22/02 Staff 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 demonstrates that the total costs are the same for all four options excluding interest and bonding. Option 2, one year recovery, is the lowest cost option because it has no additional interest or bonding costs. Option 3, existing rates continued, demonstrates the next lowest total cost. It includes $1.8 million in interest costs associated with carrying $26.1 million into the second PCA year for recovery. The third-lowest cost option is Option 4. Due to the substantial first year rate decrease it offers, it carries $96.6 million into the second year which accumulates $6.8 million in interest. Option 1, the securitization proposal is the most expensive option. Over three years it incurs $11.9 million in interest costs and $9.4 million in bonding costs. In Option 1, bond interest has been assumed at 4 percent. In Options 2, 3 and 4, interest has been assumed at 7 percent on the amount that is carried over from one year to the next. Staff witness Holm makes the Staff’s proposal concerning appropriate interest rates for PCA purposes. That proposal has not been included here due to the compressed time allowed for processing of this case. Interest differences are small and would not affect Staff’s proposal in this case. Q. Which option do you recommend to the IPC-E-02-2/IPC-E-02-3 HESSING, K (Di) 10 04/22/02 Staff 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Commission? A. I recommend Option 4, which immediately decreases rates and avoids bonding costs and some of the interest costs associated with securitization. It also recovers this year’s PCA costs in two years, which reduces the probability that a PCA true-up or forecast in the third year would push rates to higher levels than that year’s PCA alone would require. This type of exposure exists during the second year of each option except Option 2 which recovers all of this year’s PCA costs in the first year but requires an increase over existing rates to do it. Q. Have you prepared exhibits that show the impact of each of the options that you previously discussed on each of the Company’s customer classes? A. Yes I have. Staff Exhibit No. 106, pages 1 through 4 shows the expected impact of the Company’s proposal, modified to reflect the Staff’s true-up adjustments, on customer rates over the next 4 PCA years. Staff Exhibit No. 107, pages 1 and 2, shows the rate impact of Staff Option 2, single year recovery. Staff Exhibit No. 108, pages 1 through 3, shows the rate impact of Option 3, current rates continued. Staff Exhibit No. 109, pages 1 through 3, shows the rate impact of Staff Option 4, which provides for an average 9.6 percent first IPC-E-02-2/IPC-E-02-3 HESSING, K (Di) 11 04/22/02 Staff 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 year decrease without securitization. The above analysis is limited to the effects resulting from the decisions that the Commission will make this year. Any future variations from normal water conditions or normal power supply costs may cause other rate differences in PCA years after 2002 that are not contemplated in this testimony. Q. How have you treated the $18 million in unrecovered 2001 PCA costs that are scheduled for recovery between May 16, 2002 and September 30, 2002? A. I respread the costs over full PCA years in each of the options that I have presented. The drawback of respreading the $18 million to recover these costs is that summer energy users receive lower rates that are paid by winter energy users. It is a trade-off that eliminates multiple PCA rate changes in the same year. Also $18 million is a relatively small amount of the $253 million that I am proposing for recovery. CUSTMER CLASS RATE DESIGN Q. How does the Company propose to adjust rates within customer classes to recover PCA costs? A. Idaho Power proposes that the energy rate within each customer class be adjusted by an equal cents/kWh amount (i.e., a flat rate) to recover the approved revenue. Schedules without energy-based rate IPC-E-02-2/IPC-E-02-3 HESSING, K (Di) 12 04/22/02 Staff 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 components, such as lighting schedules, should have rates adjusted by an equal percentage amount that recovers the required revenue. Q. Do you agree with the Company’s proposal? A. Yes, except for residential class rates. Staff witness Schunke addresses the design of Residential rates in his testimony. Q. Did the Commission order a portion of the costs included in this year’s PCA true-up calculation be recovered from a specific class of customer? A. Yes. Orders in two different cases required that intervenor funding awarded to the irrigation class be included in the PCA and be recovered from irrigators. This would require that the PCA rate for irrigators be different than the PCA rate for all other customer classes. Given the very small amount subject to recovery and the fact that the PCA is not set up to apply different rates to different customer classes, Staff suggests that the $20,134 in question be spread to all customer classes. Apparently the Company also proposes to do this since it is included in the “Intervenor Funding” line on Company Exhibit No. 3 that is spread to all customer classes. Q. Are the rates shown in Column 9 of Staff Exhibit Nos. 106, 107, 108 and 109 the energy rates that IPC-E-02-2/IPC-E-02-3 HESSING, K (Di) 13 04/22/02 Staff 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 would result from the four proposals that you have reviewed? A. No. The rates shown in Column 9 of the referenced Staff exhibits are average rates that are calculated using all revenues normally received from the class. The actual energy rate for each customer class, which is the base energy rate plus any PCA adjustments, is shown as the “effective rate” on each of the Company’s rate schedules. DSM RATE RIDER Q. Given that electricity wholesale market prices have returned to more normal ranges since the price spikes that occurred in 2000 and 2001, what is Staff’s position regarding Idaho Power’s proposal filed July 31, 2001 in Case No. IPC-E-01-13 to implement additional conservation efforts that would be funded through a 0.5% energy surcharge? A. The Staff position essentially remains the same as when it filed its comments on September 20, 2001. Although many of the conditions that caused the wholesale electricity price spikes have now abated, some conservation and other demand side management (DSM) measures may be economically viable resources for meeting customer demand. In addition, having a DSM funding mechanism and programs in place allows a quicker ramp-up IPC-E-02-2/IPC-E-02-3 HESSING, K (Di) 14 04/22/02 Staff 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 of DSM efforts in the event that wholesale electricity prices increase dramatically in the future. Q. In that case the Staff supported Idaho Power’s proposed energy surcharge based on 0.5% of the Company’s base revenue requirement. It was estimated that the surcharge would provide approximately $2.6 million annually for DSM measures. Does the Staff still support this amount of DSM funding? A. Yes. Q. What DSM rate would result from 0.5% of base revenue spread over normalized energy in this case? A. The DSM rate rider would be 0.0192 ¢/kWh. The actual calculation is: (.005)(508,321,215)/(13,209,552)=0.192 $/MWh = 0.0192 ¢/kWh. Q. Do you propose to include the DSM rate rider in rates as part of this filing? A. Yes. Due to the extremely compressed processing time associated with this case, the DSM rider is not shown in the calculation of rates anywhere in this filing. Q. How do you propose the DSM rate rider be incorporated into the Company’s rates? A. The DSM rate rider can either be added to the first year rates calculated in this case, causing smaller IPC-E-02-2/IPC-E-02-3 HESSING, K (Di) 15 04/22/02 Staff 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 IPC-E-02-2/IPC-E-02-3 HESSING, K (Di) 16 04/22/02 Staff decreases or larger increases, or the tariff rider can be added with an equivalent amount of true-up costs being deferred to the following year. The latter would not affect first year increases or decreases but would affect rates throughout the remainder of the recovery period by a relatively small amount. With regard to Staff’s proposal in this case, I recommend that $2,541,606 of additional PCA true-up costs be deferred to the 2003 PCA year with interest. So doing allows the customers to receive the full decrease proposed by Staff for this PCA year. Q. Does this conclude your direct testimony in this proceeding? A. Yes, it does.