IPCE9515.docx

BRAD PURDY
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO  83720-0074
[phone]
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 REVISING THE RATES, TERMS AND CONDITIONS UNDER WHICH IDAHO POWER PURCHASES NON-FIRM ENERGY FROM QUALIFYING FACILITIES.
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CASE NO. IPC-E-95-15
COMMENTS OF THE
COMMISSION STAFF
COMES NOW  the Staff of the Idaho Public Utilities Commission by and through its attorney, Brad M. Purdy, Deputy Attorney General, and in response to the Amended Notice of Modified Procedure issued by the Commission in this case on November 7, 1996, submits the following comments.
In late October 1995, the Idaho Power Company (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 (“qualifying facilities” pursuant to the Public Utilities Regulatory Policies Act of 1978 (PURPA)) of small amounts of nonfirm power utilizing a variety of sources including, among others, cogeneration, photovoltaic and small hydro.
This matter has been before the Commission on two earlier occasions.  The first was for a decision regarding how to process the case.  At that time the Commission chose to handle the matter under Modified Procedure.  The second occasion was for the Commission to resolve the relevant issues.  At that time, the Commission resolved all issues except one which was remanded to the Company to develop a potential solution.  This memorandum offers comments on that solution.  A brief history and summary of the case, as well as the Company’s original proposal, is also provided.
HISTORY
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, Idaho Power therefore 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.
On July 17, 1996, the Commission conducted a decision meeting to resolve the issues presented by the Company’s proposal.  The last time the Commission visited this case it decided three of the issues and deferred making a decision on a fourth pending a subsequent proposal by the Company.  Paraphrasing, the Commission made the following decisions:
1.Eliminate the 3 mil capacity adder.
2.Reduce the number of compliance filings made with the Commission under Schedule 86 from monthly to semi-annually.
3.Eliminate Option “A”, the fixed rate supplier option.
4.Maintain rate Option “C”,  generally known as running the meter backward, with certain modifications.  These modifications entailed calculating a rate structure that captures the following requirements:
A.Allows the Company to use their existing billing system.
B.Allows customer to use a conventional “single meter” metering system.
C.Charges the customer the rate consistent with their class of service while the meter is running “forward”.
D.Pays the customer the avoided cost rate when the meter is running “backward.”
E.Charges the customer a minimum fee that is consistent with the amount backup supply and capacity they are being provided.
Item Number 4 was remanded back to Idaho Power to develop a proposal that would fulfill these requirements.  The Company’s solution is the subject of these comments.  Also, a copy of the Company’s proposal for the revised Option C is attached.
STAFF ANALYSIS
Option A
This is the revised avoided cost option listed as Option B in the still current Schedule 86.  It moved up a notch in the numbering scheme with the Commission’s decision to eliminate the Standard Rate option which was formerly listed as Option A
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Staff has no comments on Option A other than to say that, as presented in the Company’s September 18, 1996 revised tariff proposal, it appears to be consistent with the Commission’s July 17 decision.
Option B
This is the former Option C, “running the meter backward.”  This is the option that the Commission deferred decision on until such time as the Company could suggest a mechanism for charging for such things as distribution and reserve capacity costs.
Monthly Charge
The Company has developed a methodology that calculates a Monthly Charge (Net Photo Voltaic Charge (NPVC)) that depends on a number of variables, including class of service rate, avoided energy costs, hours of sunlight, and rated photovoltaic (PV) output.   As suggested by its name, this monthly charge is unique to PV producers.  It is Staff’s conclusion that, for PV producers, IPC’s proposal for calculating the monthly charge functions in a manner consistent with the Commissions’s requirement to:
A.Allow the Company to use their existing billing system.
B.Allow customers to use a conventional “single meter” metering system.
C.Charges the customer the rate consistent with their class of service while the meter is running “forward.”
D.Pays the customer the avoided cost rate when the meter is running “backward.”
E.Charges the customer a minimum fee that is consistent with the amount backup supply and capacity they are being provided.
Staff notes that while Option B is not limited to photovoltaic suppliers, this particular monthly charge is.  As such, the Company will have to revisit this issue each time a customer with a different type of generation technology requests access to Option B.  Given the current and expected workload associated with processing schedule 86 applicants, Staff does not consider the case specific nature of this monthly charge to be a major problem.
However, Staff believes that it is possible to develop a monthly charge (s) that is consistent with, and sufficiently broad to work with any and all forms of qualifying generation.  Further, Staff believes that the development and use of such a monthly charge in this tariff would be of benefit to the public, the Company, and the Commission.
Tariff Simplicity
In the section of the tariff dealing with the monthly charge, the Company states that it “will compute a charge to be added to the seller’s monthly retail billing.”  The Company then lists the items and formulas that will be used in the computation.  Staff has examined the methodology as presented in workpapers and agrees that it performs as desired.  Unfortunately, the formula provides accuracy at the expense of simplicity.  By this, Staff means that potential customers cannot immediately discern what their monthly charge will be by looking at the tariff sheet.  Arriving at that number will require one or more additional intermediary interactions between the Company and the prospective customer.
It is Staff’s observation that customer understanding of the tariff could be improved by listing a table of monthly charges associated with discreet ranges of installed capacity.  The table could be developed with the same methodology and formulas.  It would show one approximate monthly charge for customers with PV systems between 0 KW an 10 KW, and a different approximate monthly charge for customers with PV systems between 10 KW an 20 KW, etc. up to the 100 KW limit.  The table would carry the understanding that actual monthly charges will vary depending on the specifics of each customer’s installation.  The addition of such a table has the potential to substantially reduce Company and Commission interaction with potential Schedule 86 customers.
Rate Schedules 1 and 7 Only
In the Company’s original filing Option B was titled, “Offset Against Retail Sales - Facilities Under 100 KW Only.”  In the latest filing, the phrase “Rate Schedules 1 and 7 Only” has been inserted.
Staff recognizes that this option has, and will likely continue to have, a limited following. Staff also recognizes that the allure of Option B may be further diminished for customers in classes other than 1 and 7.  However, Staff sees no reason to add this further limitation of applicability.
Conditions of Purchase and Sale
In the existing tariff, item 8 of the Conditions of Purchase and Sale reads as follows: “Except under Rates, Option C, metering will be provided for recording net output or the Facility and will be separate from metering of the Seller’s load.”
In the proposed tariff, the qualifying section, “Except under Rates, Option C” has been removed, an omission that would have the effect of requiring Rate Option C customers to install additional metering equipment.  To the extent that this action is clearly at odds with the Commission’s decision regarding the maintenance of Rate Option C, the phrase exempting Rate Option C customers should be revised to say “Except under Rates, Option B....” in recognition of the new listing of rates and reinserted into Item 8 of the Conditions of Purchase and Sale.
Comments from Other Parties
Other interested parties have commented that IPC’s proposal penalizes the producer.  Staff notes that, to the extent that the commentors mean that this proposal does not pay the PV producer as much as the rate structure it replaces did, they are correct.  Staff further notes that to the extent that this proposal eliminates the incentive aspects of the existing schedule, they are also correct.  However, to the extent that it pays producers an amount consistent with the rates that other energy providers are paid for their production, while at the same time charging them an amount consistent with the level of backup energy and services they have access to, they are incorrect.
DATED  at Boise, Idaho, this            day of December 1996.
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Brad Purdy
Deputy Attorney General
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Tony Jones
Economist
BP:TJ:jo\umisc\comments\ipce9515.bp2