990128vbp.docx

DECISION MEMORANDUM
TO:COMMISSIONER HANSEN
COMMISSIONER NELSON
COMMISSIONER SMITH
MYRNA WALTERS
TONYA CLARK
BILL EASTLAKE
DON HOWELL
STEPHANIE MILLER
KEITH HESSING
DAVID SCOTT
WORKING FILE
FROM:BRAD PURDY
DATE:JANUARY 28, 1999
RE:CASE NO. IPC-E-98-13; APPLICATION OF IDAHO POWER COMPANY FOR AUTHORITY TO INCLUDE QUALIFYING FACILITY POWER PURCHASE CONTRACTS IN THE COMPANY’S 1999 PCA FILING
On November 2, 1998, Idaho Power Company (Company) filed an Application with the Idaho Public Utilities Commission to revise its Power Cost Adjustment (PCA) mechanism.  The revision requested by Idaho Power Company would update the power cost projection formula to include changes in PURPA contract costs that have occurred since the Company’s last general rate case, Case No. IPC-E-94-5.
On December 10, 1998, the Commission issued a Notice of Modified Procedure soliciting comments in response to the Company’s Application.  The only party to submit comments is the Commission Staff.  Idaho Power filed a response.
STAFF ANALYSIS
Staff’s comments in this case are divided into two parts.  Staff first addresses an error it perceives in the way PCA true-up calculations are currently made that has become apparent in Staff’s review of the Company’s current filing.  Second, Staff will address the PCA projection formula.  This is the appropriate sequence, Staff contends, since the true-up error correction affects the correction of the PCA projection formula.
PCA True-up Calculation
Staff contends that changes in PURPA QF contract costs are passed through Idaho Power’s PCA true-up mechanism to customers at 100 percent while only 90 percent of the associated power supply benefits are passed back to customers through the true-up mechanism.  “Associated power supply benefits” are reductions in system fuel costs and/or reductions in system purchased power costs and/or increases in system non-firm sales revenues.  Staff believes that it was not the intent of the Commission to create this mismatch when the PCA was established.  The Commission set the recovery of increased QF costs at 100 percent to reflect the fact that the Company was required by law to purchase this energy.  It set the recovery of changes in other power supply costs at 90 percent to provide the Company an additional incentive to manage those costs.  The case that established Idaho Power’s PCA mechanism was largely about changes in power supply costs associated with water conditions.  It is Staff’s belief that the potential for large amounts of unrecovered ratepayer benefits due to the previously described mismatch was overlooked when the PCA was established.
Fixing the mismatch is simple, Staff argues; the remaining 10 percent of the benefits should be calculated and added back in the true-up calculation.  This is demonstrated on Attachment A with four lines added in the “QF Deferral” section and enclosed in a box for emphasis.  This is a hypothetical example demonstrating what the true-up calculations from the most recent PCA filing would look like with the Staff proposed change added.  This change causes the PCA true-up calculations to capture an additional 10 percent of the estimated power supply benefits associated with increased QF energy.  This 10 percent when combined with the 90 percent of QF benefits that are already captured in the PCA true-up calculation provides a fair balance to the 100 percent of QF costs also captured there.
The Company’s quantification of additional normalized QF cost since the last general rate case is $17,768,080 per year.  This represents a 52 percent increase in QF costs.  The associated increase in normalized QF energy since the last general rate case is 255,813 MWh per year which represents a 45 percent increase in QF energy.  The estimated power supply benefit of the increased QF generation is $4,308,000 per year and the 10 percent that is not currently captured in PCA true-up calculations is approximately $430,000.  Idaho’s jurisdictional share of that amount is approximately $365,000.
PCA Projection Formula
Once the true-up spreadsheet is corrected as described above, the PCA projection formula can be designed.  The goal of the projection formula should be to project the Company’s power supply costs such that the end of year true-up is minimized.  The projection formula consists of three parts.  First, a regression equation that relates power supply costs to April through July streamflow runoff volumes into Brownlee Reservoir.  This is the only part that has been allowed to vary in PCA projections to date.  The second part of the PCA projection formula is the expected cost of QF contracts in the coming year.  In all PCA filings to date, QF costs have simply been projected at their normalized base level even when it was known that they had increased substantially and that the increase would require a substantial end of year true-up.  Third, projected power supply costs associated with FMC second block power are removed because FMC second block power is excluded from PCA treatment by Commission order.
Staff proposes two changes to the QF contract cost projection portion of the formula.  First, that the cost projection include the net cost of known QF contract changes since the base was established and second, that 100 percent of net cost differences be projected to be passed back to ratepayers.  This is consistent with Staff’s previous recommendation that QF costs and benefits be trued-up at 100 percent.  Costs and benefits of additional QF generation are to be captured in the projection as a “net cost”, costs less benefits.  Attachment B is a hypothetical example, again taken from the Company’s last PCA filing, which demonstrates these calculations.
The bottom half of Attachment B calculates the “Net Cost of Additional QF Energy” and adds it to Base QF contract costs to obtain “Forecast QF Contract Costs”.  “Forecast QF Contract Costs” are carried to the upper portion of the page where they become the QF Contracts Forecast.  The remainder of the calculations on the upper half of the page determine the PCA forecast “Energy Rate” with 100 percent of QF Contract net costs forecast to be passed to ratepayers and 90 percent of other power supply projections of cost to be passed to ratepayers.
Company Proposal versus Staff Proposal
Staff’s proposal differs from the Company’s in two material ways.  The Company’s filing contains no proposal to change the PCA true-up mechanism.  By not changing the true-up mechanism, the PCA will continue to include 100 percent of increased PURPA costs and only 90 percent of the associated power supply benefits.  Staff proposes to change the PCA true-up mechanism such that 100 percent of the power supply benefits associated with increased QF costs are captured along with 100 percent of the increased QF costs.
The Company’s proposal for the projection is to include the total increase in QF costs, without any offsetting benefits, and to further project that 90 percent of those costs will be passed back to customers.  By so doing the Company’s proposal overstates the expected net costs actually captured in the true-up and causes a true-up difference which is carried into the following year.  Staff proposes to project increased QF net costs and to further project the recovery of those costs at the 100 percent level which is consistent with the way that Staff proposes these costs be treated in the true-up calculation.
Staff Recommendation
At the present time the PCA true-up mechanism captures 100 percent of additional QF costs incurred since the QF base was established in the Company’s last general rate case but only 90 percent of the associated power supply benefits.  Staff recommends that the Commission revise the PCA true-up calculations such that 100 percent of the power supply benefits associated with changes from base QF energy amounts are captured to partially offset 100 percent of the associated costs that are currently being captured.  This can be done in the true-up in a two step process.  The first step is to recover 90 percent of the benefits.  The existing calculations already do this, therefore, no changes are needed.  The second step recovers the remaining 10 percent of benefits.  In order to accomplish this the four lines contained in the box on Attachment A must be added to the current true-up calculation.
Staff also recommends revision to the projection method used in the PCA.  Staff recommends that differences in net costs, costs less benefits, between base and expected actual QF conditions be projected and passed on to customers at the 100 percent level.  Attachment B to these comments demonstrates these calculations.
Staff further recommends that these PCA changes be implemented at the beginning of the next PCA year which is April 1, 1999.
Idaho Power Response
On January 27, 1999, Idaho Power filed a response to Staff’s comments.  Initially, Idaho Power states that it is “in agreement that a reduction in the Company’s proposal will reduce the true-up amounts resulting from the PCA projection formula.”  The Company states that it has no objection to the Staff’s reduction of the QF constant within the PCA cost projection to $47,574,349 from the Company’s proposed $51,882,240.  Idaho Power emphasizes that regardless of whether the Company’s original proposal or Staff’s adjustment to the Company’s proposed PCA projection formula is used, there will be no affect on the total PCA costs that will be recovered.  The parties are simply attempting to formulate the best cost projection method possible.
Idaho Power concludes that because it has no objection to Staff’s formula and $308,000 adjustment to the Company’s proposal, Idaho Power will accept the QF constant of $47,574,349 in the PCA projection formula to be used in the 1999 PCA filing.  
Idaho Power objects to Staff’s proposed adjustment relating to capturing 100% of QF-related benefits.  The Company takes exception to Staff’s characterization of the existing methodology as “an error in the PCA calculation.”  Idaho Power contends that when the Commission issued Order No. 24806 implementing the PCA for the first time, it fully intended that 100% of the Company’s QF costs would flow through the PCA and that only 90% of fuel, purchased power and surplus sales variations would be tracked.
Idaho Power contends, that in the proceeding underlying Order No. 24806, certain parties, including Staff, argued that the Company should not be permitted a 100% pass through of any cost components.  The Company argues that the Commission agreed with Staff and other parties with respect to non QF components stating that “if we were to allow 100% of those costs to be passed through to ratepayers, the Company would not have the same degree of incentive to minimize those costs as it would if some degree of sharing is retained.”  The Company posits that Staff’s position that QF costs be treated like all other costs was specifically rejected by the Commission which, Idaho Power argues, recognized that unlike all other power supply costs, the Company does not exercise judgment or discretion in the acquisition of QF resources or the cost of that acquisition.
Idaho Power argues that Staff’s proposal in this case to correct the purported “mismatch” between QF costs and benefits “reopens the legal debate surrounding QF power acquisitions by the Company.”  Idaho Power suggests that Staff’s position in this case is tantamount to a request to modify Order No. 24806 to the detriment of Idaho Power.  The Company concludes that it is inappropriate to raise this issue in a revenue neutral application and where there is an insufficient record to debate the issue.
Commission Decision
(1) Does the Commission wish to modify Idaho Power’s PCA forecast mechanism to include changes in PURPA contract costs?
(2) Should Staff’s proposal to account for 100% of associated QF benefits be adopted?
(3) Should Staff’s alternative PCA calculation method be adopted?

Brad Purdy
bp2/M:IPC-E-98-13