Attch14_IPCE0134_StaffComments.doc

JOHN R. HAMMOND
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 5470

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

Attorney for the Commission Staff

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION OF IDAHO POWER COMPANY FOR AN ORDER APPROVING THE COSTS TO BE INCLUDED IN THE 2002/2003 PCA YEAR FOR THE IRRIGATION LOAD REDUCTION PROGRAM AND ASTARIS LOAD REDUCTION AGREEMENT. )
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CASE NO. IPC-E-01-34

COMMENTS OF THE
COMMISSION STAFF
COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its Attorney of record, John R. Hammond, Deputy Attorney General, and submits the following comments in response to Order No. 28893, the Notice of Application and Notice of Modified Procedure in Case No. IPC-E-01-34 issued on November 9, 2001.
On October 18, 2001, Idaho Power Company filed an Application for a Commission Order approving the costs from the Irrigation Load Reduction Program and the Astaris Load Reduction Agreement to be included in its 2002/2003 Power Cost Adjustment (“PCA”). The costs included in the Application are those costs booked through September of 2001.

IRRIGATION BUY-BACK PROGRAM
On May 25, 2001, the Commission issued Order No. 28699 in Case No. IPC-E-01-3 giving final approval to an irrigation buy-back program for Idaho Power Company. The irrigation buy-back took place during the 2001 irrigation season and required that participants sell Idaho Power a minimum of 100,000 kWh over the course of the irrigation season. The Commission established the price that the Company would pay at 15 ¢/kWh. At the time of program approval forward market prices for the irrigation season were near 30 ¢/kWh. Because of projected high market prices, the program was expected to provide a win/win situation for both farmers and ratepayers. Farmers who participated would win because they would receive payments for not using energy, and Idaho Power ratepayers would win because the Company would obtain the buy-back energy at a cost lower than the alternative market purchase. Therefore, reduced costs would be passed on to customers through next years PCA rate adjustment. The direct costs of the program are simply 15 ¢/kWh for all kWh’s bought back.

STAFF AUDIT
Staff has audited the amounts requested by the Company for the irrigation buy-back program by tracing all costs back to workpapers that substantiate the Company’s request. Staff has also reviewed a random sample of customer accounts and determined that they were all accounted for properly. Staff verified that the amounts requested by the Company are based on the best information the Company had at the time it filed.
During its audit, it became apparent to Staff and the Company that the simplistic way the costs are calculated in the irrigation buy-back program will require a number of true-ups that will have to be determined as more information becomes available. True-ups are needed because of meter reading errors, customer changes, additions and deletions of metered locations, changes in the method of calculation and reporting, and other items. These changes will make it impossible to calculate the full cost of the program until at least January 2002. Staff has reviewed the amounts included in this filing and finds that $63,162,233 is the appropriate amount to include in the PCA calculation for the period of April 2001-September 2001 before the sharing percentage and the Idaho allocation. After the allocations are made, Staff calculates the Idaho PCA portion to be $48,319,108. There will be additional true-ups to the April-September amounts as more information becomes available, mathematical errors are corrected and the Company includes items that have been excluded. Staff reserves the right to audit the additional true-ups for reasonableness as they become available.
An unanticipated complication in the program is that some participants have been paid for energy that they did not save. In one or more early months they received payments for energy savings that they used before the end of the program. Idaho Power will have to collect the overpayments from these customers. The associated costs should not be borne by other ratepayers. Staff recommends that the Company be required to track these overpayments and exclude them from irrigation buy-back costs that are included in the PCA.

REDUCED REVENUE
In its order the Commission allowed for Company recovery of the direct costs of the program and also the recovery of an undetermined amount of “reduced revenue” through the PCA Mechanism. In this specific case, reduced revenue is revenue that the Company does not receive from the sale of electricity when it buys that electricity back from its customers. Reduced revenue is also called “lost revenue”. In the ordering paragraph, the previously referenced order states:
IT IS FURTHER ORDERED that the direct costs and lost revenue
impacts of this Program may be treated as a purchased power expense
in the Power Cost Adjustment. The Commission also finds that Idaho
Power and the parties shall develop and present a proposal to the
Commission recommending a procedure to calculate the appropriate
amount of lost revenues that should be passed through the Company’s
Power Cost Adjustment mechanism prior to actual recovery in rates.

Order 28699, at 21
On September 27, 2001, Idaho Power met with the Commission Staff and other parties and interested individuals and discussed the reduced revenue issue. Idaho Power presented a proposed lost revenue calculation that included the recovery of energy and demand related revenues associated with irrigation kWh’s bought back. The Company reduced this initial calculation by 1.684 ¢/kWh to account for a credit already incorporated in the PCA when actual energy sales are reduced. This prevents a double counting of this portion of lost revenue. During the meeting the Company also agreed to reduce lost revenue by the cost of losses that it does not incur when it buys energy back. Average delivery losses are 10.8 percent of delivered energy for irrigation customers taking service at the secondary voltage level. Since reduced revenue is to be included in the PCA, it is jurisdictionally allocated and further reduced by 10 percent before it is finally deferred for future recovery from ratepayers. Attachment A demonstrates this calculation for one kWh bought back. The proposed methodology produces a cost that will be passed on to Idaho ratepayers of approximately 16.75 ¢/kWh for every kWh bought back.
At the reduced revenue meeting, attendees, other than Idaho Power, demonstrated little enthusiasm concerning the prospect of reduced or lost revenue recovery regardless of the calculation method. However, little was said in opposition to lost revenue recovery in general. The Company has chosen this case for resolution of that issue.
Staff’s general position regarding lost revenue remains unchanged from that stated in the initial case and summarized in the Commission’s Order as follows:
Staff believed that recovery of at least a portion of lost revenues was justified in this case despite Commission rulings in the past to the contrary. Lobb, Tr. at pp. 42-43. Staff asserted that this case is different than traditional demand side management (“DSM”) programs because the energy savings associated with this Program are more easily quantified as each irrigator has bid to forego consuming a certain amount of energy at a set price for a single year. Id. This is a significant difference from multi-year, engineering estimate type calculations of savings occurring in traditional DSM programs. Id. Staff also pointed out that because the energy reduction occurs during a single year it would not be subject to test year true up in a general rate case as would long term reductions associated with traditional DSM programs. Id. However, Staff opined that the Company should not profit unduly from this Program. Lobb, Tr. at p. 43. Rather, Staff recommended that Idaho Power be allowed to recover at least the portion of lost revenue that will make the Company no worse off with the Program than without it. Id. Thus, the outcome should be revenue neutral. Id. Staff recognized that Idaho Power might not agree with this proposal but pointed out that the Company has the responsibility as a public utility to keep charges made for the services it provides “just and reasonable.” Idaho Code § 61-301. Staff asserted that this responsibility in combination with the current market situation make it clear that the Company should emphasize the development and implementation of programs that reduce power supply costs because failure to do so could be deemed imprudent.

Staff also commented that there is uncertainty in measuring energy reduction due solely to this Program because it is quite possible that some irrigators would not have farmed at all or would have switched to a crop that required less water even if this Program had not been offered or that energy use may also be reduced if the pumping season is shortened due to lack of water. Therefore, Staff suggested that lost revenues should be reduced to account for these factors. Id.

The issue of lost revenues is further complicated by the Company’s presumption that there is an entitlement to projected sales that might have occurred without the Program. The projected volume of sales most certainly includes some sales due to growth. To the extent that growth in any customer class can be offset with this or any other energy buy-back programs that are more cost effective than market purchases, the Company’s liability is reduced. Staff argued that to the extent energy associated with growth is offset by this Program, the Company should not be entitled to recovery of the associated revenues through a lost revenue adjustment.

Staff recommended that there should be no disincentives for the Company to secure the least cost power supply options. At the same time, Idaho Power should not be enriched for doing what would be expected to minimize negative economic impacts on its customers.
The amount of lost revenue that would give the Company “zero” benefit should be calculated at the conclusion of the Program this fall.

Order No. 28699, at 6-7.

In Idaho Power’s initial filing in the case that established the irrigation buy-back, Case No. IPC-E-01-3, the Company proposed that the recovery of lost revenue was appropriate. The Company’s initial position was to recover lost demand and energy revenues with no offsetting adjustments. As a result of discussions with Staff and other parties to the case, the Company has agreed in this filing that lost demand and energy revenues should be reduced by 1.684 ¢/kWh that is captured in the PCA as a result of negative load growth and delivery losses at 10.8 % of the energy bought back. It is Staff’s position that these adjustments along with the 10 % PCA sharing reduction in all of the costs of the program prevent any “enrichment” to the Company as a result of proposed Commission approval of lost revenue recovery.
The 90/10 sharing adjustment also addresses, in a general way, concerns that the Staff expressed about free riders in its previous comments. The fact that 10 % of program costs will not be passed back to ratepayers provides increased assurance that free riders would not cause the program to be uneconomic. This is in addition to the Company’s position on free riders, that by establishing a buy-back price well below the expected market price the impact of a few unavoidable free riders would still allow program costs to remain below expected market prices.
Staff has audited the Company’s lost revenue calculations through the month of September and finds that they follow the Company’s recommendation. In its filing the Company points out that the transmission loss calculation has not been included but commits to include an adjustment for all past months in its final calculations.
Staff proposes that irrigation buy-back program costs be calculated as proposed by the Company and discussed above with the one additional adjustment previously discussed. That adjustment is a reduction to program costs for buy-back payments made to customers who were paid for energy that, in the final analysis, they did not sell back.

ASTARIS BUY-BACK
On April 10, 2001, the Commission issued Order No. 28695 in Case No. IPC-E-01-9 approving Idaho Power Company’s application to buy-back 50 MW of firm load from Astaris. The buy-back contract is to run through the end of Astaris’s current power supply contract with Idaho Power that expires on December 31, 2003. The 50 MW’s is to come from Astaris’s 120 MW first block service under the supply contract, which is take or pay. The terms of the buy-back contract require Idaho Power to pay Astaris 86.5 % of the forward market price at the time the contract was entered into. This price averaged approximately 15.9 ¢/kWh over the contract life. Since Idaho Power clearly needed the power and the power could be obtained at a price below the expected market price the Commission approved the buy-back. The Commission’s order allows the costs of the program to be recovered through the PCA mechanism.
Reduced revenue is not an issue in the Astaris buy-back. The Astaris take or pay contract guarantees that Idaho Power will receive revenue for the sale of 120 MW from Astaris through the end of 2003. During each month of the April 2001 through September 2001 period, Astaris paid Idaho Power for 120 MW of power, although it received only 70 MW, and Idaho Power paid Astaris to not use 50 MW. Idaho Power has paid Astaris the full contract amount of $55,035,321 less $460,270 in penalties for small portions of the 50 MW used by Astaris and not sold back to Idaho Power. This nets to $54,575,051. The Idaho jurisdictional share and PCA sharing reduce this amount to $41,749,914. Staff has reviewed the calculation of this amount and finds it to be accurate.
The Company and Staff have discussed two other adjustments to the Astaris buy-back costs that are similar to cost adjustments previously discussed in the irrigation buy-back program. Idaho Power has agreed to reduce program costs for losses and to include 120 MW of Astaris load each month in the “Actual Firm Load” for the load adjustment calculation in the PCA. Including the Astaris load at 120 MW prevents the PCA calculation from automatically including 1.684 ¢/kWh of lost revenue when there is no lost revenue as previously discussed. Neither of these adjustments are included in the booked amounts through September of 2001.
Astaris has recently announced that it is closing its production facility. Both of its contracts with Idaho Power, the take or pay power supply contract and the buy-back contract, continue through December 31, 2003. If no other agreement is entered into, Astaris will pay Idaho Power approximately 2.3 ¢/kWh plus the PCA rate adjustment for 120 MW of energy each month and Idaho Power will pay Astaris an average rate of 15.9 ¢/kWh for 50 MW of energy. The remaining 70 MW not used by Astaris will be sold on the market when market prices are higher than fuel costs. The profits from the sale will be captured in the PCA and 90 % of those profits will be returned to ratepayers. When market prices are lower than fuel costs, 70 MW of energy will not be generated and 90 % of the fuel cost savings will be passed back to ratepayers through the PCA.

RECOMMENDATIONS
Staff recommends that the Commission:
Allow $48,319,108 from the April 2001 through September 2001 irrigation
buy-back program to be included in the PCA deferral.
2. Allow $9,783,625 from the April 2001 through September 2001 irrigation
buy-back program to be included in the PCA deferral to compensate Idaho
Power for reduced revenues.
3. Allow $41,749,914 from the April 2001 through September 2001 Astaris load
reduction payments to be included in the PCA deferral.
4. Allow interest to accrue on the outstanding balances as established in the PCA
calculation.
Accept the Company’s offer to reduce irrigation buy-back and Astaris buy-
back power supply costs for losses not incurred because of the programs.
Require the Company to track irrigation customers that received payments for
energy that they did not save and exclude the associated costs from the PCA
account.
7. Require the Company to track all adjustments and true-ups for Staff audit
when the information is available.

Respectfully submitted this day of November 2001.

__________________________________
John R. Hammond
Deputy Attorney General

Technical Staff: Keith Hessing
Alden Holm

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STAFF COMMENTS 1 NOVEMBER 30, 2001