970320.docx

DECISION MEMORANDUM
TO:COMMISSIONER NELSON
COMMISSIONER SMITH
COMMISSIONER HANSEN
MYRNA WALTERS
TONYA CLARK
DON HOWELL
STEPHANIE MILLER
DAVE SCHUNKE
KEITH HESSING
DAVID SCOTT
WORKING FILE
FROM:BRAD PURDY
DATE:MARCH 20, 1997
RE:CASE NO.  IPC-E-96-25; IDAHO POWER’S APPLICATION FOR APPROVAL OF TARIFF (SCHEDULE 20) PROVIDING FOR OPTIONAL MARKET-BASED SERVICE TO CUSTOMERS FROM 5 TO 10 MEGAWATTS
On December 19, 1996, the Idaho Power Company (Idaho Power; Company) filed an Application seeking approval of a proposed Schedule 20—“Market-based Pricing Service Pilot Program.”  Schedule 20 is a pilot program providing optional market-based service to customers who contract for 5 to 10 megawatts of firm demand at one point of delivery.  This voluntary optional service will provide these customers with the choice between the fixed prices offered under Schedule 19 (large industrial) and the combination of fixed and variable prices (tied to energy markets) offered under Schedule 20.  In addition, Idaho Power contends, it will provide these customers experience with market-based prices.  The Company states that it also will benefit by gaining experience with pricing methodologies outside of the standard embedded cost framework.  Idaho Power notes that it currently has 10 customers who could potentially take service under Schedule 20.
Customers who elect to take service under Schedule 20 may have all or as little as one-third of their load priced at market prices.  The Schedule provides two options as market proxies:  The Dow Jones—California—Oregon border (DJ-COB) index and the futures contracts traded on the New York Mercantile exchange (NYMEX) for the California-Oregon border (COB) delivery point.  Customers who choose to have only a portion of their load priced on the market will have the remainder of their load priced at an embedded fixed cost rate.  The required term of the agreement for service under Schedule 20 is three years.  The portion of customers’ loads that is based on the fixed price will remain at that price throughout the term of the Agreement.  At the beginning of each year, however, customers may move their market-based load from one of the two options to the other.  The Company proposes that, if approved, Schedule 20 will be available for all agreements entered into on or before December 31, 1997.
The energy price under the variable (market-based) price options includes an adder of 3.6 mills, which is intended to ensure that customers participating in the pilot program do not receive any preferential treatment (i.e., avoid making a contribution towards earnings and required CSPP purchases) at the expense of other standard tariff customers.  The adder is comprised of two components. The return component is designed to recover the same return in mills per kWh as the embedded fixed price proposed under Schedule 20.  The CSPP component is designed to recover above-market CSPP.  The demand and customer charges, as well as any energy taken under the fixed price option, under Schedule 20 are based on the embedded costs of service under Schedule 19 as detailed in the Company’s cost-of-service study mentioned above and adjusted to reflect the Commission’s decision in Order No. 25880 and 26236 (Case No. IPC-E-95-5: The Twin Falls case).
Energy sales priced under the variable price options will not be subject to the Company’s annual PCA treatment but will impact PCA calculations.  Monthly energy sales priced under either of the variable price options will be removed from the Idaho jurisdictional sales for PCA purposes.  This removal will result in a revised jurisdictional allocation for PCA purposes, which the Company contends will properly match the share of the variable expenses allocated to the Idaho jurisdiction with the jurisdictional customers participating in the PCA.  Any energy sold under Schedule 20 which is priced under the fixed price option will be included in the Idaho jurisdictional sales and will be subject to the PCA.
Idaho Power notes that due to the energy market, it is not possible to predict whether the Company may experience an increase or decrease in revenues during any particular year as a result of participation in Schedule 20.  The Company further notes that in order for the schedule to be implemented, it is necessary for the actual revenues received from the pilot program to flow through the earnings test mechanism established in Case No. IPC-E-95-11 as part of the Company’s rate stability agreement.  Idaho Power states that if any recalculation of revenues associated with the pilot program is determined to be a condition for implementation of the program, the Application would be withdrawn by Idaho Power.
Idaho Power has requested an effective date of January 20, 1997, and requests that this matter be handled under Modified Procedure.  Staff agrees that Modified Procedure is appropriate, but requests that the Commission issue an Order suspending the proposed effective date to allow time to solicit and review comments and issue an Order accordingly.
On January 21, 1997, the Commission issued a Notice of Modified Procedure soliciting comments in response to Idaho Power’s Application.  Comments were submitted by the Commission Staff and the Industrial Customers of Idaho Power.  
Commission Staff
Staff agrees that attempts to gain experience with pricing methodologies outside of the standard embedded cost framework is ample justification for experimentation.  Staff cautions, however, that Schedule 20 service should not be construed to provide broad based experience in electric utility competition.  Staff argues that Schedule 20 is relatively narrow in scope.  For example, it does not allow other service providers to sell electricity to any of the eligible customers.  Furthermore, Schedule 20 service provides no experience with energy purchasing.  Neither Idaho Power nor the Schedule 20 participants will purchase energy from the open market as a result of this experiment.
The portion of load that a customer allocates to the index pricing mechanism will be priced at a running average of the D.J. COB spot market prices.  The customer will not be buying and selling the energy directly.  The portion of load that a customer allocates to futures prices is open to more options but is still limited, Staff contends.  This pricing option allows customers to hedge their prices via futures purchases and sales prior to the 15th day of each month.  The cutoff date of the 15th day of the month, however, places limitations on the customer that would not exist if the customer had full access to the wholesale market.
Another limitation contained in the Company’s proposal relates to the customer’s ability to change its mix of futures purchases relative to spot purchases.  Such changes, Staff notes, are only allowed once per year.  In an open competition situation where the customer has access to wholesale markets, if and when such markets exist, the customer will be able to make these choices over very short time periods, perhaps hourly.  At a minimum, Staff contends, in a deregulated industry, it is likely that agri businesses will want to change their portfolios with the season.  Clearly, Schedule 20 does not offer that flexibility.
Staff concludes that Schedule 20 is precisely what the Company says it is.  It allows some Schedule 19 customers direct access to (1) fixed cost rate and (2) market-based variable rates.  It is not, however, a broad based experiment in retail competition or customer choice.  It is a very focused experiment involving a few industrial customers with limited pricing options.
Idaho Power proposes that energy sold under the Schedule 20 fixed price option be included in the PCA and that energy sold under either of the variable price options be excluded from PCA treatment.  Staff supports the Company’s recommendation.  The variable price options should already reflect current and expected regional weather and water conditions as well as other factors.  To add the PCA to variable energy prices would appear to double count.  
Staff notes that it could be argued that the true-up portion of the PCA in the first year should be spread to all Idaho jurisdictional customers since the true-up is composed of deferred costs or benefits accumulated prior to approval of this Schedule 20 option.  Since true-ups have been historically small, however, Staff asserts that it does not make administrative sense to capture and return the true-up portion of the PCA separately to Schedule 20 customers participating in a variable energy price option.  Staff contends that including a PCA rate adjustment in the variable price options would change the price the customer is trying to beat in order to finish financially better off.  Thus, the market price signal would be distorted and the results of the pilot could not be directly attributed to pure market-based prices.
Idaho Power proposes that the actual revenues associated with service under the Schedule 20 option be allowed to flow through the earnings test as opposed to recalculated revenues based on Schedule 19 rates.  Because of the value of the experiment, Staff is willing to accept this proposal, but not without some concern.  Staff does not know if the customers who choose to participate in the program will ultimately pay more or less than they would pay under Schedule 19.  It is unlikely, however, that any customer will voluntarily sign up for Schedule 20 service unless that customer believes there is money to be saved.  If Schedule 20 customers do save money, then Idaho Power’s earnings will be lower than they would be otherwise.  Lower earnings translate into a reduced opportunity for all customers to share in earnings above 11.75% on equity and an increased chance that earnings will fall below 11.5% on equity resulting in the use of accelerated deferred tax credits to bring earnings to the minimum level.  
In conclusion, Staff believes that the Company’s filing meets the requirements of the Commission’s Order No. 26555 issued in Case No. GNR-E-96-1 in which the Commission stated “we are supportive of any type of pricing that is responsive to customer needs so long as the net revenues collected from those customers are fair and do not place an undue burden on other customers.  Again, we encourage the utilities to be creative in this regard.”  Id. at p. 8.  
Staff notes that its recommendation for approval should not be construed to imply agreement or disagreement with the philosophies or methods used by the Company in the rate unbundling process.  
Industrial Customers of Idaho Power (ICIP)
The ICIP advocates a system of regulation under which individual customers have unlimited access to competitive markets for electricity.  The ICIP views the Company’s proposal in this case as a timid, tentative step in the direction of market access.  The ICIP has the following specific comments regarding the Company’s proposal.  
Market Proxy Identification
The ICIP contends that the options for the market price proxy should be expanded to include the mid-Columbia trading hub which is a more accurate reflection of northwest regional market prices.  Such information, while not published in the Wall Street Journal, is readily available to the public.  An additional acceptable market proxy would be to use Idaho Power’s off system sales prices as another benchmark for the non-fixed energy charge component of Schedule 20.
Term of Agreement
The ICIP argues that the required three year term of the agreement is too long because there is a high probability that federal and state legislation will become a reality before the mandatory three-year term proposed under Schedule 20 expires.  In addition, the ICIP contends, realities of the market do not suggest long-term commitments to a single vendor of non-firm spot energy products.  Indeed, long-term commitments for purchasing spot market commodities is somewhat of a contradiction.
The ICIP proposes that a more realistic approach would be to permit the ICIP to enter or exit the market pursuant to market dictates.  This would result in no harm to Idaho Power or its ratepayers, the ICIP argues, because Schedule 20 customers will continue to pay Idaho Power’s demand charges, all identified above market CSPP, a return component on all energy purchased under the variable price options, and surrogate transmission costs.  
Maximum/Minimum Load Under Each Option
The ICIP argues that there should be no minimum and no maximum level of participation on either the fixed price option or on the variable price option because in open markets, the customer determines the level of risk he or she is willing to bear.  
Changes in the Amount of Fixed Price Load
Again, the ICIP contends that in order to make Idaho Power’s offering a more effective experience with pricing methodologies, the customer should be permitted to change the magnitude of its fixed price load as market conditions change.  The ICIP contends that it is not reasonable to expect customers to remain locked-in at their initial selection for a three-year period.
Duration of the Experiment
Idaho Power proposes that no new agreements be entered into after December 31, 1997.  When coupled with the mandatory three year contract term, the ICIP contends, this tariff will effectively expire on December 31, 1999.  The ICIP argues that while the tariff is in effect, customers should be permitted to contract for any term within the parameters of the effective date of the tariff.  In other words, should a customer seek a one year contract beginning on January 1, 1999, it should be permitted to do so.  The term of the agreement should not be dictated, the ICIP contends, because flexibility in accessing the markets is a key component of a competitive electric system.
Future Prices Under the NYMEX Variable Price Option
The ICIP argues that the monthly pricing option for futures contracts on the NYMEX should be extended to whatever length futures contracts are being traded at the time the Schedule 20 customer chooses this option.  The ICIP states that this recommendation is nothing more than a refinement of Idaho Power’s proposal by extending the futures contracts to more accurately reflect contracts available at the time the option is selected.
Rate of Return Adder On Variable Price Options
Idaho Power proposes a surcharge on the variable rate under Schedule 20 in the amount of 1.9 mills per kWh to recover the Company’s rate of return on each kWh sold.  The ICIP argues that the Company will not suffer lost sales as a result of implementation of Schedule 20.  The ICIP contends that Schedule 20 is in reality a “virtual open access tariff” in the sense that it indexes Idaho Power’s rates to an objective market rather than setting those rates through the traditional ratemaking process.  The addition of a rate of return component, the ICIP asserts, does not accurately reflect the markets for electricity nor does it aid in the prediction of customer behavior towards those markets.  If the addition of a rate of return adder sets the commodity price too high in comparison to the market, then the seller (in a competitive market) would lose customers and market share.  Conversely, if an open market can absorb higher profits for the seller, the seller should be permitted to sell at the higher rate.  The ICIP argues that if this experiment is to be successful as a predictor of the Company’s customers’ reactions to market opportunities, then Idaho Power should be willing to join its customers by assuming some market risk.  Adding a guaranteed return component to the price does nothing to mimic the market, the ICIP asserts.
CSPP Adder
The ICIP contends that the CSPP adder is in reality the Company’s surrogate identification of its stranded costs.  While acknowledging that CSPP costs must be recovered as a condition precedent to a fully deregulated environment, the ICIP notes that the Commission has made no findings as to what those costs are, how they will be recovered or who is responsible for their recovery.  The ICIP asks that the Commission, should it approve Schedule 20, explicitly disclaim any possible precidential effects on the identification of stranded costs or the recovery of those costs in the future.
Four Mill Adder for Monthly Pricing Option
ICIP notes that Idaho Power defines off peak pricing as on peak less four mills.  The ICIP argues, however, that recent peak/off peak price spreads are much greater than four mills.  Consequently, either the actual spread should be used or a more realistic number should be adopted.
Demand Charges
The ICIP states that Idaho Power’s demand charges since Schedule 20 are derived from its cost of service study.  Therefore, by definition, they are not an accurate reflection of the market or market prices for capacity or firm power.  The ICIP concludes that “a more accurate experiment would included [sic] an attempt to match current market prices for capacity.
Impact on Remaining Customers
The ICIP argues that, contrary to the Company’s proposal, its is not necessary for actual  revenues received from the pilot program to flow through the earnings test mechanism.  The ICIP states that “if the Commission were interested in the true market test, in which all players are operating on equal footing, then the revenues (and/or lack of revenues) from Schedule 20 would be outside of the ratemaking process.  Only in that way would the Company be motivated to respond to the market as a rational economic player.”  Comments at p. 7.
Idaho Power Response
On March 4, 1997, Idaho Power filed a letter in response to the ICIP’s comments.  Idaho Power states that, after reviewing the ICIP’s comments, the Company agrees with the ICIP’s recommendation to expand the monthly price option to allow customers to specify a monthly price for any month for which futures contracts are trading.  Idaho Power attached a proposed revised tariff that would accomplish this in the event the Commission deemed appropriate.
Commission Decision
Does the Commission wish to approve a market-based price experiment for Idaho Power’s industrial customers with Schedule 19 loads between five-ten megawatts?  
If so:
(1)Should the Company be required to offer variable prices at the mid-Columbia trading hub?
(2)Should the Company be required to offer terms shorter than 2-3 years?
(3)Should the Company be required to allow a customer’s full load to be placed on any of the three Schedule 20 pricing options?
(4)Should the Company be required to allow customers to change the magnitude of their Schedule 20 fixed price load as market conditions change?
(5)Should customers be allowed to contract for any term within the experiment?
(6)Should customers be allowed to lock-in NYMEX futures prices for the period of time that futures contracts are being traded as opposed to one month at a time?
(7)Should the Company be required to reduce or eliminate the proposed 1.9 mill/kWh return on production?
(8)Should the Commission explicitly disclaim any precedential effects on the determination of stranded costs that result from the approval of the Company’s filing?
(9)Should the peak/off-peak price differential be four mills/kWh as proposed by the Company or increased or set at the actual differential?  If set at actual, how is that to be determined?
(10)Should market prices for capacity replace Idaho Power’s proposed Schedule 20 demand charges?  If so, how should market-based capacity charges be determined?
(11)Should Schedule 20 revenues flow through the earnings test?
Brad Purdy
vld/M:IPC-E-96-25.bp