960711.docx

DECISION MEMORANDUM
TO:COMMISSIONER NELSON
COMMISSIONER SMITH
COMMISSIONER HANSEN
MYRNA WALTERS
TONYA CLARK
DON HOWELL
STEPHANIE MILLER
DAVID SCHUNKE
KEITH HESSING
GARY RICHARDSON
WORKING FILE
FROM:BRAD PURDY
TONY JONES
DATE:JULY 11, 1996
RE:CASE NO.  IPC-E-95-15
IN THE MATTER OF THE APPLICATION OF IDAHO POWER COMPANY FOR AN ORDER REVISING THE RATES, TERMS AND CONDITIONS UNDER WHICH IDAHO POWER PURCHASES NONFIRM ENERGY FROM QUALIFYING FACILITIES
In late October 1995, the Idaho Power Company filed an Application for an Order (1) approving revisions to the Company’s current Schedule 86 entitled “Cogeneration and Small Power Production – Nonfirm Energy”; (2) approving revisions to the rates to be paid for nonfirm energy sold to Idaho Power under Schedule 86, and; (3) authorizing the Company to file documentation supporting the computation of purchase rates under Schedule 86 on a semi-annual rather than a monthly basis.
Sellers under Schedule 86 are typically QF generators of small amounts of nonfirm power utilizing a variety of sources including, among others, cogeneration, photovoltaic and small hydro.
This matter was previously before the Commission for a decision regarding how to process the case.  The Commission chose to handle the matter under Modified Procedure.  This memorandum will summarize the comments received.  A summary of the Company’s original proposal is also provided.
In 1980, the Commission directed Idaho Power, in Order No. 16025, Case No. P-300-12, to purchase nonfirm energy from Schedule 86 suppliers based on the Company’s system avoided energy cost, plus a small amount in consideration of system capacity benefits.  In compliance with the Commission’s directive, Idaho Power files, each month, a schedule with the Commission showing nonfirm energy prices based on the Company’s monthly incremental variable cost of energy used to serve the Company’s marginal 175 MW increment of system load.  The filed schedule is based on data for average fuel cost, operating and maintenance expenses (which vary with the output of thermal plants), firm power purchases and spot market purchases.  In addition to its monthly variable energy cost, Idaho Power adds a 3 mill per kWh “aggregate capacity” amount to represent the “system capacity benefits” provided by Schedule 86 suppliers, as required by Order No. 16025.
IDAHO POWER’S PROPOSAL
The Company contends that in 1980 when the Commission was considering implementing Schedule 86, a number of parties argued that in the future there would be a sufficient number of QFs selling nonfirm energy at all times to justify a capacity payment based on an aggregation of nonfirm energy resources.  The Commission accepted the argument at that time and required the Company to include the 3 mill aggregate capacity adder to nonfirm rates.  Idaho Power contends that actual experience has shown that an aggregation of nonfirm resources has not materialized.
According to the Company, nonfirm sales under Schedule 86 to Idaho Power are generally of short duration and occur on an intermittent basis.  The Company states that only one large QF has received regular payments under Schedule 86 for more than a few months and that particular QF has now converted its sale to a long term, firm sale.  Furthermore, Idaho Power notes that only two QF projects are currently selling nonfirm energy on a regular basis under Schedule 86.  Those two projects have capacities of 110 kW and 261 kW, respectively.  The Company argues that nonfirm energy purchases under Schedule 86 have never provided any actual capacity to Idaho Power’s system.  Because it does not avoid any capacity purchases as a result of nonfirm energy purchases from QFs under Schedule 86, therefore, Idaho Power asserts that it would be appropriate to eliminate the 3 mill aggregate capacity adder.
Idaho Power further proposes to reduce the number of compliance filings it makes with the Commission under Schedule 86.  The Company would still compute the incremental variable cost of energy on a monthly basis but would only file the rate computation data with the Commission semi-annually as opposed to monthly.  Idaho Power suggests that this is reasonable considering the small number of QFs selling to the Company under the schedule.
In its current form, Schedule 86 contains three rate options for suppliers.  Option “A” is a fixed rate.  Option “B” is a variable rate based on the Company’s system avoided energy cost.  Option “C”, known as “running the meter backward” allows suppliers to utilize the power they generate to actually reduce the amount of energy they take from Idaho Power.  Idaho Power  proposes to eliminate the existing Rate Option A.  Only two small QFs are currently being paid under this option.  The Company notes that nonfirm energy purchases from these two smaller projects could continue at the variable energy rate proposal (Option B) under the revised Schedule 86.  Idaho Power asserts that the variable energy rate more accurately reflects the actual costs the Company can avoid by purchasing nonfirm energy from QFs and, therefore, elimination of the Option A would benefit Idaho Power’s customers.
Finally, the Company proposes to eliminate the existing  Option C titled “Offset Against Retail Rates.”  This option essentially allows a QF developer to be paid the retail rate for nonfirm energy by using his own generation to run his meter backwards.  The option was designed to be available only to very small facilities (under 100 kilowatts) and only one QF ever elected to utilize the option.  The single QF currently selling under the option would be grandfathered under the Company’s proposal but no additional QFs could elect Option C.
COMMENTS
Commission Staff
I.  Elimination of the 3 Mill Aggregate Capacity Adder
Staff agrees with the Company that, because of the fact that there has been minimal small power production within the state, the capacity benefits provided by Schedule 86 generators are minimal or nonexistent.  Staff does not oppose, therefore, the elimination of the 3 mill aggregate capacity adder.
II.  Elimination of the Option A
Staff advocates retaining the fixed rate arguing that it is needed to allow small power producers to obtain financing and to plan production.  Staff also believes that there must be a mechanism in place for the timely updating of the amount of this rate.  To accomplish these two ends, Staff recommends maintaining Option A with the following modifications:  (1) to bring the rate into line with current avoided costs and provide for timely updates, Staff proposes basing the fixed rate on the avoided cost as calculated and published in the Company’s IRP and updated by successive IRPs; (2) to prevent QFs from abusing periodic swings in the difference between the IRP avoided costs and the spot market, the proposed standard rate would only be available to suppliers contracting to sell the power exclusively to Idaho Power for a 24-month period.
III.  Elimination of Rate Option C (Net Metering, i.e., Running the Meter Backwards)
This portion of Idaho Power’s proposal is the most contentious as evidenced by the many comments received in opposition.  Staff believes that Rate Option C, in its current form, creates a situation where the Company may be obligated to purchase electricity at prices well in excess of either current generation costs or avoided costs.  This is because a self-generator who runs his meter backwards essentially substitutes the lower Schedule 86 rate he would have been paid by the Company with the higher retail rate he would have paid for his own usage had he not run his meter back.  Realistically, the current Option C should be titled “Net Metering at a Single Rate.”  In other words, in the case of a residence, if the site is a net user of electricity over the course of a month it pays the residential rate for that net usage.  If it is a net producer of electricity over the same period, it gets paid the same residential rate for the net production.
Staff recommends retaining Option C but changing it to a method that could be titled “Net Metering at Alternate Rates.”  In other words, when the residence is a net user of electricity over the course of a month, it will would pay the residential rate for the net usage.  If it is a net producer over the same period, however, it will only be paid the fixed (avoided cost) rate.  Staff’s proposal could easily be implemented without requiring the suppliers to install additional metering equipment. The downside to the self-generators is that they will no longer be subsidized by the amount that the regular rate exceeds the avoided cost rate when they generate a surplus.
As discussed below, there were numerous comments received by the Commission advocating the retention of Rate Option C.  Essentially, those comments argue that (1) net metering is common in other states, (2) net metering is intended for small generators, (3) net metering is inexpensive because it does not require a switching mechanism, dual meters, additional accounting procedures or on-site storage systems, (4) net metering provides a subsidy to socially desirable forms of generation, and (5) the amount of the subsidy, because of the paucity of generators involved, is sufficiently small as to be inconsequential.
Staff concedes all of the foregoing points but counters with the following observations: (1) Staff’s proposal requires no additional equipment that is not required under the current Option C, (2) Staff believes that the programming required to implement Staff’s proposal is minimal, (3) Staff’s modified Option C continues to give the self-generator the benefit of offsetting electrical consumption at the charged rate, but only up to the extent that monthly generation equals or is less than usage.  Beyond that point, the Company would pay a lower avoided cost rate for any surplus electrical production.  Staff believes that this approach continues to send the right message while at the same time eliminating an unjustified subsidy.
As an aside, Staff notes that as an individual’s electric bill approaches zero, by the process of self-generation, Idaho Power will be under-earning on the portion of the distribution system and service drop required to provide that individual with full backup power.  The amount of this under earning also constitutes a small subsidy that has not been discussed by either Idaho Power or the proponents of Rate Option C.
IV.  Calculation of Avoided Costs
Idaho Power does not base its calculation of Rate Option “B” on avoided costs.  Rather it bases the rate on the most costly 200 MW of firm generation actually produced in the preceding month.  This means that the QFs producing under Option B will not know the price they will receive for their generation until well after it has been produced, thus presenting a situation where it is possible for a developer to produce power at a loss without realizing it until after the fact.
Staff notes that this approach is substantially different from the traditional concept of avoided costs.  Staff does not oppose the use of this definition in this situation.  Regarding the effect of this proposal, however, Staff envisions that these avoided cost rates will have limited appeal to QFs.  Staff believes that rates based on such avoided costs will appeal primarily to developers in transition to providing firm energy or to others who are comfortable with the highly speculative nature of this rate.  To that end, and with the assumption that most nonfirm producers will choose the Rate Option “A” discussed earlier, Staff does not oppose this option.
Others
Idaho Department of Water Resources (IDWR)
The IDWR opposes the elimination of Rate Option C arguing that it is beneficial to the utility as well as the customer and has no adverse impact on ratepayers.  The IDWR contends that without net metering, the utility must install one meter to measure power consumption and another to measure power production, thereby increasing overall retail rates for every customer class.
The IDWR contends that although only one very small customer has elected to utilize Option C, the option has not been well publicized and Idaho Power has not identified any burden that retaining the option would place on the Company or its customers.
The IDWR characterizes net metering as simply another form of demand-side management; no different than credits given by a utility to its customers who implement energy conservation measures to reduce their electrical consumption.  The IDWR contends that net metering allows small power producers to receive the fair market value for the power they are producing just as Idaho Power receives for the photovoltaic rooftop installation on its headquarters building.
The IDWR notes the attention and accolades that Idaho Power has received for the implementation for its photovoltaic program and questions why the other potential applications of photovoltaic such as customer generation through net metering does not receive the same level of promotion.  The IDWR contends that this technology has tremendous potential for on-grid applications in the residential and commercial sectors.  Maintaining Option C under Schedule 86, therefore, would be a good policy and offers and incentive for Idaho Power customers to explore this opportunity.
Marjorie G. Hayes
Ms. Hayes, opposes the elimination of Rate Option C contending that it would discourage the development of alternative supply resources including the production of energy from manure which she contends poses a health risk if not disposed of.
Gene Bertsche–Alternative Energy Consultant and Salesman
Mr. Bertsche, who resides in Arizona, asserts that the alternative energy industry relies heavily upon opportunities presented by net metering.
Mr. Mark Moser–Resource Conservation Management, Inc.
Mr. Moser notes that self-generators typically do not install their projects for the profits received from electricity generation but simply as a means to help pay for the primary process such as waste treatment.  Mr. Moser purports to have experience with Idaho dairy farms who desire to improve their waste management by installing anaerobic digesters to stabilize the waste, control odor and generate methane.  He asserts that Option C is critical to small producers because these projects are marginal at best.
Mr. John Smith–Mountain Section, American Institute of Architects
Mr. Smith, who resides in Ketchum, believes that the elimination of Rate Option C would be a step backwards in the architectural profession’s efforts to provide alternative power supplies and sustainable systems for buildings and infrastructure.
Charlie Woodward–Natural Resource Co.
Mr. Woodward contends that, contrary to Idaho Powers assertions, net metering is a thing of the future rather than the past.  He argues that there is a developing market for “green” power and states are increasingly mandating the development of these alternative resources.
David VanHersett–Forest Fuels, Inc.
Mr. VanHersett has attempted to develop several small cogen projects in Idaho since 1982.  He contends that in each case, the utility in question successfully prohibited him from developing alternative resource projects.  The most recent project to fail was the 400 kW demonstration project at Samuels, Idaho.  The failure of the project, however, seems to have been related to the imposition of an interconnection cost by the BPA.  In any event, Mr. VanHersett contends that there is interest in Idaho for the development of alternative resources including the 100 kW back pressure steam turbine demonstration project sponsored by the IDWR and completed in March of this year.  Mr. VanHersett contends that this type of project can produce approximately 50% of the annual energy requirements of a typical small sawmill in Idaho.
Peter Chaffey
Mr. Chaffey emphasizes that self-generators are not in the business of selling power to the utility and agrees that restrictions should be in place to prevent people from becoming net producers under Rate Option C.  He contends that the elimination of Rate Option C in its entirety, however, would be an affront to the notion of conservation and the development of renewable energy resources.
Les Nelson–California Solar Energy Industries Association (CAL SEIA)
CAL SEIA represents over 100 companies involved in the manufacture, sales and distribution of solar energy equipment in California and elsewhere in the United States.  Several of its members are actively involved in manufacturing and selling photovoltaic equipment which is used in Idaho.  CAL SEIA notes that California recently signed into law net metering legislation and at least 13 other states have similar laws in place.  CAL SEIA argues that net metering removes a significant impediment to private investment in clean renewable technologies while encouraging resource diversity.
Idaho Rivers United (IRU)
IRU stresses that incremental changes, such as the one proposed by Idaho Power in this case, need to be considered in the larger context of the electric industry and the changes facing both the industry and consumers.  IRU contends that renewable energy resources and conservation is consistently favored by the public and that Idaho Power’s proposal is anathema to public sentiment.
Idaho Power Reply
Idaho Power argues that the QF industry in Idaho has matured to the extent that it no longer needs the same degree of stimulation and protection from competition afforded in the past.  In addition, the Federal Energy Regulatory Commission (FERC) has reaffirmed the tenet that public utilities cannot be required to pay more than their avoided costs for purchases of power from QFs.  This is particularly critical, Idaho Power argues, as the industry faces the specter of deregulation and the potential of stranded costs.
Idaho Power objects to Staff’s characterization of Option B under Schedule 86 as a “new method of calculating avoided cost.”  According to the Company, this same purchase option has been in place since the original Schedule 86 was filed in 1981.  The Company concedes that this method of pricing QF energy is certainly different from the estimated avoided costs traditionally associated with firm energy QF contracts in Idaho.  It is consistent, the Company argues, with the FERC’s regulations governing purchases of “as available” energy.  The FERC regulations allow utilities to price nonfirm or “as available” energy received from QFs either based upon utilities’ avoided costs calculated at the time of delivery or based on energy or capacity value pursuant to a legally enforceable obligation over a specified term in which case the rates shall, at the option of the QF, be based on either the avoided cost calculated at the time of delivery or the avoided cost calculated at the time the obligation is incurred.
With regard to the elimination of rate option “A”, Idaho Power argues that this is justified because the option requires that the Company estimate future energy costs.  Idaho Power contends that this is becoming increasingly difficult given the substantial changes that are occurring in the wholesale power markets.
In reply to Staff’s suggestion that the standard rate option facilitates QFs’ attempts to obtain financing, the Company questions whether nonfirm energy prices play a significant role in the evaluation of the long term viability of QF projects by potential project financiers anyway.  Nevertheless, Idaho Power is willing to accept Staff’s proposal to retain rate option “A” in Schedule 86 as an alternative to purchases based on actual avoided costs at the time of delivery.  This acceptance is conditioned on the Company’s ability to revise these estimated rates on a regular basis.  The Company agrees that Staff’s proposal to revise the rates every two years is reasonable.
Idaho Power argues that Rate Option C allowing very small QFs to run the meter backwards and sell their power at retail rates rather than at avoided cost rates should be eliminated for at least two reasons.  First, retail rates exceed Idaho Power’s avoided cost rates as approved by the Commission.  Consequently, purchasing nonfirm energy at retail rates violates PURPA.
Second, and as Staff notes, the current Option C prevents the Company from recovering all of its cost of serving those retail customers that sell power under this option.  Not only will the Company be under-earning on its investment required to serve a particular customer with respect to the distribution system and service drop costs required to provide self-generators with full backup power, the retail rates that Idaho Power charges its retail customers cover more than just the Company’s generation costs.  Retail rates also include costs associated with the Company’s transmission system, its distribution system and all of the other costs associated with providing retail electric service.  Consequently, if the QF runs the meter backwards to zero, none of these nongeneration costs are recovered from the QF.  Staff’s proposal to modify Option C to require purchases of net generation at avoided cost rather than at retail rates, therefore, does not avoid the under-earning problem.
Furthermore, the Company argues, the O&M charges under Schedule 72 are designed for QF projects generating in parallel with the Company’s system and do not recover all of the system costs attributable to self-generators.  These cost recovery issues for self-generators have been dealt with by the Commission for years, the Company notes.  Traditionally, utilities and commissions have resolved these problems by means of a standby or backup charge allowing the utility to recover, from the self-generator, his equitable share of the costs of the backup he receives from the utility system.  Standby charges are intended to minimize the risks that other customers will be disadvantaged by a self-generator’s decision to generate to its own load.
Idaho Power notes that there is currently a substantial movement to “unbundle” the delivery of electrical services in order to send the right price signals to customers.  The Company argues that net metering, (i.e., running the meter backwards) allows one group of customers to shift system costs to other customers and sends price signals that are inconsistent with unbundled electric service.
Commission Decision
1.Does the Commission desire to eliminate the 3 mill capacity adder?  (This proposal was not opposed by any party.)
2.Does the Commission desire to reduce the Company’s compliance filing schedule from once per month to once every 6 months? (Not opposed.)
3.Does the Commission desire to maintain the Rate Option “A” (fixed rate) with the condition that Idaho Power be allowed to revise the rate every two years consistent with the revision of avoided costs as published in its IRP?
4. Does the Commission wish to retain Rate Option “C”; running the meter backwards?
If so, should Staff’s proposal to pay suppliers the avoided cost rate for net production be adopted?

Brad Purdy, Deputy Attorney General
_______________________________________
Tony Jones, Economist
bls/M-ipce9515.bp2