27211.docx

(text box: 1)BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE COMMISSION’S OWN INVESTIGATION INTO THE COSTS INCURRED BY IDAHO’S ELECTRIC UTILITIES IN PROVIDING ELECTRIC SERVICE.
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CASE NO. GNR-E-97-1
ORDER NO.  27211
On September 18, 1997, this Commission issued a Notice of Scheduling and Proposed Order No. 27134 setting forth the Commission’s initial conclusions regarding the separation of electric providers’ costs in fulfillment of legislation (House Bill No. 399; Idaho Code §§ 61-338,  -339) recently enacted by the Idaho Legislature.  Generally speaking, the Proposed Order endorsed a methodology presented by Idaho Power to the Commission earlier this year as a model for Idaho’s other electric providers to use as a guide in providing this information.  The Proposed Order established ground rules for cost categorization and asked interested parties to comment.  The Order further scheduled a technical workshop for the Commission Staff and representatives of electric providers for the purpose of resolving some technical issues.  Finally, the Order posed four technical questions to be addressed at the workshop.
Set forth below are summaries of the results from the technical workshop as well as the comments received in response to the Proposed Order.
TECHNICAL WORKSHOP
Uniform System of Accounts
The Order proposed that the Uniform System of Accounts (USOA) should form the basis of all analyses.  All participants agree with the use of the USOA.  The Idaho Consumer-Owned Utility Association (ICUA) advocated use of the USOA for its members.
Reporting Period
All participants agree that the use of a 1996 calendar year is appropriate.  It was agreed that the ICUA members can provide data based on a fiscal year rather than a calendar year 1996 basis if that is the reporting period they utilize for other purposes.
Normalization
At the workshop, the regulated utilities agreed that test year data normalized for weather and stream flows was acceptable, while cooperative and municipal utilities which have not performed such normalizing studies would not be required to do so.  It was noted that normalizing adjustments impact generation costs.
Jurisdictional Separation
The Order proposed that costs should be stated on an Idaho jurisdictional basis.  Idaho Power questions the merit of requiring that costs be stated on an Idaho jurisdictional basis at this time.  To the extent that costs are allocated to jurisdictions in a similar manner, after which they are then computed on a per unit basis, the system results should mirror the jurisdictional results on a per unit basis.  Nonetheless, the utilities agreed to perform this analysis and state costs on an Idaho jurisdictional basis.
Embedded Costs
The parties agreed with the Order’s provision that embedded costs should be used.  
Cost of Capital
It was conceded that the regulated utilities’ current authorized cost of capital should be used as proposed by the Commission.  The cooperatives and municipals will incorporate a reasonable, surrogate cost of capital into their analyses.
Unbundling by Voltage Level
Because existing customer class divisions are not as homogeneous as might be desired, the Commission proposed to separate costs based on voltage level.  The parties agreed that costs should be separated at voltage levels for arriving at values that are comparable.  It was acknowledged that data of the various utilities may not allow for exactly the same definitions of the small and secondary voltage categories.  The participants agreed that when providing voltage level information, all suppliers will provide clear definitions of their voltage categories.  
Report Format
The Order requested the filing of information in both electronic and hard copies with work papers.  The utility participants agreed to provide the information in both hard copy and electronic form.  Also, following the issuance of this Order, the Staff will provide an electronic reporting format to be completed by all utilities.
Allocation Methodology
In terms of allocation, the Idaho Power methodology takes the approach of doing direct assignment of costs to functions whenever possible.  If direct assignment is not possible, costs are allocated in a manner consistent with Commission-approved methodologies.  The participants propose that each party be allowed to allocate administrative and general costs or general plant in a manner consistent with regulatory methodologies established specifically for them.  It was agreed that ICUA members will use an appropriate allocation methodology.
Generation
Because the generation resource mix for each utility is different, a fixed/variable cost split analysis may tend to be skewed when total plant investment is considered to be a fixed cost.  Idaho Power, for instance, has traditionally allocated a portion of the fixed costs of generation to variable energy-related costs using the company’s system load factor.  Idaho Power’s cost separation report filed in July of this year splits total production costs into variable and fixed components using its traditional allocation methodology.  Idaho Power believes, however, that a more meaningful split of fixed/variable cost for a hydro-based utility would be through the application of the system load factor.    Here again, the participants propose that each party be allowed to allocate generation costs in a manner consistent with regulatory methodologies established specifically for them.
The parties agree that rather than using the terms “fixed generation costs” and “variable generation costs,” the Commission should adopt the terms “demand-related generation costs” and “energy-related generation costs.”  This distinction recognizes the fact that the investor-owned utilities categorize the majority of fixed production costs as energy-related.
Transmission and Distribution, Metering, Meter Reading, Billing and Other Customer Services
The Order adopts the following transmission distribution cost categories:
Transmission
Distribution Facilities
Metering
Meter Reading
Billing
Other Customer Services  
The parties agree with these cost categories.  Because uncollectible accounts expense relates to generation, transmission and distribution services and is not a cost of billing, however, Staff proposes that the billing costs category be detailed further to show uncollectible accounts as a separate item within that category.
Public Purposes
   The Commission adopted the following public purpose cost categories:
Demand Side Management (DSM) Cost
Fish Mitigation
Alternative Energy Sources
Universal Service
Low Income Assistance
The utilities all noted that they have little or nothing in terms of low income assistance costs.  To the extent there are any, they propose the costs be included in the DSM category.  For the DSM category, there will be differences in costs caused by disparate expense/deferral treatments and amortization periods.  The utilities will note the various amortization time frames for DSM costs.
It has been noted that will be difficult to identify costs that belong in the Fish Mitigation category.  The utilities have agreed to make their best effort at providing this information.  It was also agreed that there are currently no universal service costs for electric providers.  The category can remain as a placeholder for future costs that may materialize.  As explained further below, we direct that DSM, Fish Mitigation and alternative energy categories be stated as part of the generation costs.
Miscellaneous
The Proposed Order included four technical questions.  The answers of the participants at the technical workshop are as follows:
(1) What should be the boundaries between generation, transmission and distribution?  The participants agreed that the Uniform System of Accounts provides the appropriate boundary definitions.
(2) Is there equipment installed on one part of the system designed to benefit another functional part of the system?  The answer is yes; however, the difficulty associated with separating out these costs combined with the fact that it would be an insignificant difference in the separated cost categories make the effort not worthwhile at this time.
(3) How should administrative and general (A&G) costs be allocated?  Each utility allocates or assigns A&G costs differently now with similar goals of including them in the appropriate cost category.  These costs amount to roughly 10% of total revenue requirement.  Each investment-owned utility will allocate A&G costs as approved in its last general rate case.  The ICUA members will allocate A&G costs in an appropriate manner of their choosing.  In all cases, the detailed methodology will be shown in work papers provided with the reports to the Commission.  
(4) How should general plant be allocated?  Once again, each utility has traditionally done this allocation differently.  The participants agreed to follow the same format as with respect to A&G costs.
COMMENTS
Idaho Retailers Association (Retailers)
The Retailers agree that public purpose costs including demand side management, fish mitigation, alternative energy sources, universal service and low income assistance should be unbundled without necessarily breaking them out on customers’ bills at this time.  The Retailers support the separation of generation costs into fixed, variable and net benefit of secondary sales revenues.  The Retailers agree that the offset of net sales revenue to generation costs is appropriate because ratepayers are financing the generation facilities used to make off-system sales.
Finally, the Retailers agree that transmission and distribution should be broken down as proposed by the Commission.  By obtaining detailed information now, the Commission and the Legislature will be prepared to address the issue of competitive distribution services.
FMC and Potlatch
FMC/Potlatch contends that although the unbundling legislation refers only to “costs” the Legislature was obviously interested in comparing existing power supply “rates” to competitive prices in the market place.  
FMC/Potlatch argues that informal workshops are not an adequate procedural vehicle for complying with the legislation.  FMC/Potlatch characterizes the Commission’s first workshop as “elementary” and notes that participation in the second technical workshop was limited to utilities and the Commission Staff.  Consequently, FMC/Potlatch argues that the unbundling methodology will be chosen with little or no input from intervenors or other interested parties.   FMC/Potlatch argues that this current proceeding will have enormous consequences for every Idaho ratepayer, alternative power suppliers and a host of other interested parties.  FMC/Potlatch contends that virtually every step in the unbundling process has the potential to shift millions of dollars between the utilities and their ratepayers and between ratepayer classes.  FMC/Potlatch contends that the Commission should not proceed any further without scheduling contested proceedings in which the crucial issues can be put to the test of a spirited debate between all interested parties.  FMC/Potlatch concludes:
If the Legislature had desired nothing more than unexamined utility submis­sions of unbundled costs, it could have accomplished that itself by simply requiring the utilities to submit data to the appropriate legislative committee.  Obviously the Legislature expected something more from the Commission than a mere passive acceptance of utility proposals. . . .
FMC/Potlatch argues that the Commission erred in adopting Idaho Power’s report as a model until all parties have had an opportunity to scrutinize and debate that report.  FMC/Potlatch criticizes Idaho Power’s report for failing to compare the power supply component of regulated rates to known market prices so that customers can determine whom to purchase their power from in the event deregulation occurs.  FMC/Potlatch concludes that the Idaho Power model is “nothing more than an academic exercise.”  FMC/Potlatch argues that the Idaho Power model should be modified to translate costs separated by voltage levels back to class rates.  
FMC/Potlatch argues that the Commission erred in categorizing alternative energy sources, demand side management, and fish mitigation as public purposes when in fact they are generation or power supply costs.  FMC/Potlatch contends that in a competitive environment, utilities must recover their power supply costs through market sales.  They cannot expect captive ratepayers to cover the cost of above-market power supplies unless a transition cost surcharge is imposed by legislation or regulators.  Public purposes costs, by contrast, are typically viewed as governmentally determined social obligations beyond the norm imposed on competitive enterprises.  Thus, most restructuring proposals provide for a public purpose surcharge.  Consequently, it is in a utility’s interest to recategorize power supply costs as public purposes costs whenever possible.  Doing so ensures recovery of the costs from captive ratepayers and lowers the utility’s power supply costs.  FMC/Potlatch questions the Commission’s proposal to include purchased power in the variable cost generation category while the net benefit of secondary sales constitutes a separate category of generation costs.  This may produce misleading results, Potlatch contends, when applied in a deregulated market.  FMC/Potlatch asserts that purchases designed to facilitate open market, secondary transactions should no longer be classified as a variable generation cost.
FMC/Potlatch argues that when further information is available, there will be many similar issues with significant economic implications that must be debated by all parties and the Commission.  The regulatory practice of categorizing some hydroelectric capital costs as variable energy costs is but one example with significant ratemaking implications.  FMC/Potlatch proposes that both variable and fixed generating costs be broken into additional subcategories such as fuel, labor, etc., on a plant by plant basis so that hydroelectric and thermal costs can be meaningfully compared.
FMC/Potlatch argues that the Commission should offer recommendations to the Legislature regarding precisely which distribution functions (i.e., metering, meter reading, and billing) are potentially competitive.  The Commission should attempt to determine which of the various ancillary services should remain a monopoly function and which should become competitive.  
Finally, FMC/Potlatch contends that the Commission must address the issue of stranded costs.  FMC/Potlatch asserts that regulated rates and market prices cannot be meaningfully compared until potential stranded costs are identified.  If delivery charges will be subject to a possible stranded  cost surcharge in an unknown amount, this entire exercise has little meaning to policy makers or customers.  If the delivery charge can’t be quantified, there will be no way to determine whether particular customers or classes will fair better or worse under a competitive market.  FMC/Potlatch proposes that the Commission at least quantify potential stranded costs now.  If it so desires, the Commission could leave the final disposition of stranded costs to the Legislature but it must at least identify the amounts in dispute and the policy implications of the positions advanced by the various parties.
Idaho Power
In its comments, Idaho Power essentially concurs with the conclusions reached by the utilities and Staff at the technical workshop.
Industrial Customers of Idaho Power (ICIP)
The ICIP argues that the agreements and compromises reached between Staff and the electric providers who attended the technical workshop will make whatever information is provided meaningless for use in comparing the relative costs of providing electric service in Idaho.  The ICIP suggests that the Commission mandate that all electric service providers use the following categories broken down by (1) customer class; (2) system wide, and; (3) voltage level.  Conservation measures, including DSM, fish and wildlife mitigation and alternative energy procurement must be included in the generation, energy supply and power delivery categories.  For each of the services identified, the ICIP contends that the electric provider should (a) provide a concise definition of the service, (b) list each account in the Uniform System of Accounts including costs properly assignable or allocable to the service and, (c) indicate which, if any, such accounts contain costs which are also properly assignable or allocable to one or more other services and if so which other services.  The ICIP recommends that the Commission adopt a rather lengthy and detailed list of cost categories.  
Idaho Rivers United (IRU)
The IRU asserts that the proposed public purpose cost category needs further consideration.  The categories listed are applicable to all types of generation except “fish mitigation.”  The IRU questions whether it is the intent of the Commission to develop different public purpose charges based on the type of generation.  If so, IRU asserts that hydro generation includes other types of mitigation for wildlife and recreation which ought to be considered.  Coal plants will not have fish mitigation costs but have equipment and operating conditions to satisfy pollution standards.  IRU argues that if coal generation air quality compliance is not a public purpose then neither should be fish mitigation.
IRU notes that it is unlikely that accurate historical information exists regarding the categories of costs classified as public purposes.  For decades, the utilities subsidized line extensions in order to provide universal service.  Those costs were not captured and will have to be reconstructed using hindsight.  Regarding fish mitigation, it is necessary to scrutinize those costs carefully if and when the utilities incur them.  IRU believes that it is not possible to state with specificity what Idaho Power’s fish mitigation costs have been.  
Finally, the IRU contends that unbundling at the voltage level should make for a clearer analysis than using customer classes.  The IRU is concerned that cost shifting ultimately may occur if distribution costs are over weighted for low voltage residential and small business customers and if current subsidies to some customer classes are not revealed in the analysis.
Washington Water Power (Water Power)
Water Power essentially concurs in the conclusions reached by the utilities and Staff at the technical workshop.  Water Power notes that most of its low-income expenditures fall into the demand side management category.
PacifiCorp
PacifiCorp essentially concurs with the conclusions reached by the utilities and Staff at the technical workshop.  PacifiCorp notes that it may not possess an exact break out of customers by delivery voltage.  It will, however, make every effort to reorganize its study to distinguish costs by certain voltage levels.
Cell Net Data Systems, Inc.  (Cell Net)
Cell Net provides advanced metering and communications technology (network meter reading and related services) to electric utilities.  Cell Net provides a synopsis of the history of  meter reading technologies.  The comments do not specifically reference the Commission’s proposed Order No. 27134.  The essence of the comments is to encourage state regulatory commissions to facilitate the entry of independent ancillary service companies into the competitive market as deregulation occurs.
Commission Staff
Staff believes that the conclusions reached in the technical workshop are consistent with the spirit and intent of the Commission’s Proposed Order.  Staff recommends that the Commission modify its final Order to reflect the modifications agreed to in the technical workshop.
FINDINGS
Having considered the comments filed in response to our Proposed Order, we find no reason to depart from our adoption of the Idaho Power study as a general model for cost separation of all electric providers, with the modifications discussed below.  We commend the commentors and participants for their efforts in resolving these complex issues.  We find that their efforts have produced a methodology that will provide meaningful cost data that will be reasonably comparable between providers.  It would be specious to suggest that the information that will be provided by the various electric providers can be compared on a dollar for dollar basis.  Variations in the resource mixes, accounting methodologies, engineering systems and management philosophies of the various providers make such an exact matching impossible.  Nonetheless, we believe that we have devised a format that will produce meaningful information regarding the costs of every provider as required by the statute and in a format that is understandable and consistent among providers.  
We also note that there seems to be unanimous support from the participants in the technical workshop regarding how the cost reports should be formatted and calculated from a technical standpoint.  Consequently, we find that the conclusions and recommendations from the technical workshop as set forth above are reasonable and are adopted for purposes of the reports required by this Order.
We now turn to the comments of the commentors to the extent that they oppose the Commission’s Proposed Order.  First, we find that FMC/Potlatch’s contention that the Legislature intended for electric providers to provide unbundled “rates” rather than “costs” is not supported by the wording of the legislation itself, nor is it feasible within the context of this proceeding.  FMC/Potlatch states that House Bill No. 399 “is not a model of statutory clarity” and concedes that it is unfortunate that the Legislature adopted the term “costs” rather than “rates.”  Nonetheless, FMC/Potlatch concludes that “what the legislature is seeking from the Commission is an independent expert factual determination that will allow legislators to compare existing power supply rates to competitive prices. . . .”  Comments at p.3.
We believe that the Idaho Legislature is aware of the difference between “costs” and “rates” and that it chose its statutory verbiage with deliberate consideration.  We do find that some of the issues raised by FMC/Potlatch are on point and should be the subject of further discussion and analysis.  It is our desire, however, that this proceeding produce electric provider cost data in the format and of the content specified in this Order in time to report to the Governor and the 1998 Idaho Legislature.  Time does not permit us, therefore, to resolve many of the complicated and contentious issues raised by FMC/Potlatch prior to the upcoming legislative session.  For that reason, upon receipt of the cost information of the investor-owned utilities, we will open three new dockets to address the issues raised by FMC/Potlatch and examine in detail the cost data provided.  No further proceedings are planned by the Commission to review the cost information that will be provided by ICUA members.
The ICIP proposed a detailed list of cost categories extending far beyond the three categories identified in the statute.  Nonetheless, we find that it would be reasonable to require that all regulated utilities and, to the extent that they can, non-regulated electric providers, provide, as part of their reports, work papers showing costs at the Uniform System of Accounts level.  We reject the ICIP’s recommendation that costs be broken down into customer class, system-wide and voltage level.   We believe it is sufficient that costs be separated by voltage level only.  To make information useful to customers, however, the reports should include descriptions adequate to allow customers to understand how the voltage level information relates to them.
We share IRU’s concerns regarding the difficulty of identifying and quantifying public purposes costs and we agree with FMC that categorizing alternative energy sources, demand-side management and fish mitigation as public purposes rather than power supply costs is apt to be misleading.  We will require utilities, therefore, to include these categories under generation costs.
All electric providers are directed to file cost reports in the format and with the cost categories specified in this Order no later than December 18, 1997.  Following the receipt of those reports by the Commission, we will issue a Notice scheduling further proceedings in this matter.
O R D E R
IT IS HEREBY ORDERED that all electric utilities and cooperative and municipal corporations providing electric energy within the state of Idaho that are subject to the requirements of Idaho Code §§ 61-338, -339, shall submit cost information in the format set forth in this Order no later than December 18, 1997.
THIS IS A FINAL ORDER.  Any person interested in this Order (or in issues finally decided by this Order) or in interlocutory Orders previously issued in this Case No. GNR-E-97-1   may petition for reconsideration within twenty-one (21) days of the service date of this Order with regard to any matter decided in this Order or in interlocutory Orders previously issued in this Case No. GNR-E-97-1 .  Within seven (7) days after any person has petitioned for reconsideration, any other person may cross-petition for reconsideration.  See Idaho Code § 61-626.
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this                  day of November 1997.
                                                                                                                                      DENNIS S. HANSEN, PRESIDENT
                                                                                           RALPH NELSON, COMMISSIONER

MARSHA H. SMITH, COMMISSIONER
ATTEST:

Myrna J. Walters
Commission Secretary
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Service Date
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