Decision 2000-11: TransAlta - 1996 Electric Tariff Application - …€¦ · provided its refiling...

Decision 2000-11 Page i February 25, 2000

TRANSALTA UTILITIES CORPORATION

1996 ELECTRIC TARIFF APPLICATION–PHASE II REFILING

DECISION 2000-11

CONTENTS

1. BACKGROUND.................................................................................................................... 1

2. THE PURPOSE OF THIS DECISION ON THE REFILING.......................................... 3

3. ADJUSTMENTS TO THE REFILED COST OF SERVICE STUDY........................... 12

4. LEVEL OF RATE INCREASES ....................................................................................... 19(a) What Base Should the 10% Cap Be Applied To? .......................................................... 19(b) Should the Board Vary Decision U99035 with Respect to the

10% Rate Increase Cap? ................................................................................................. 26(c) How Should Rate 6300 Series and Rate 6400 Series Customers be Grouped?.............. 33

5. IRRIGATION RATES – RATE 2600 TO RATE 2900 .................................................... 36

6. UNUSED INVESTMENT CREDITS OPTION 10 AND OPTION B ............................ 37

7. CHANGES TO PLANNED INTERRUPTION TRANSITIONALTERNATIVE - OPTION G........................................................................................... 41

8. DIRECT ACCESS TARIFF – RATE 6800 ....................................................................... 44

9. CONTRACT UNBUNDLING ............................................................................................ 50

10. DESIGN OF TIME-OF-USE RATES................................................................................ 52

11. OILFIELD RATES – RATE 4400, RATE 4500, RATE 4600 and RATE 6100............. 54(a) Rate 4500 - Oil and Gas (Energy) Service ..................................................................... 54(b) Rate 6100 (General Service)........................................................................................... 54

12. OTHER MATTERS CONCERNING OILFIELD CUSTOMERS ................................ 58

13. INTEREST ON INTEREST REFUND RIDER ............................................................... 61

14. SMALL GENERAL SERVICE - RATE 4100 .................................................................. 64

15. MAXIMUM INVESTMENT FOR RESIDENTIAL SERVICES ................................... 66

16. REA AND FARM RATES – RATE 2100 TO RATE 2500 .............................................. 69

17. ADEQUACY OF INFORMATION RESPONSES........................................................... 74

18. PAYMENT OF INTEREST TO THE CITIES................................................................. 78

TABLE OF CONTENTS TransAlta 1996CCPhase II Refiling

Decision 2000-11 Page ii February 25, 2000

19. ELIGIBILITY FOR RATE 2800 – REA IRRIGATION SERVICE.............................. 80

20. SUMMARY OF BOARD DIRECTIONS.......................................................................... 83

21. ORDER................................................................................................................................. 85

APPENDICES

1 ABBREVIATIONS ................................................................................................................ 88

2 REFERENCES........................................................................................................................ 90

ALBERTA ENERGY AND UTILITIES BOARDEdmonton, Alberta

TRANSALTA UTILITIES CORPORATION1996 ELECTRIC TARIFF APPLICATIONPHASE II REFILING

Decision 2000-11Application RE95081

File 1204-6

Decision 2000-11 Page 1 February 25, 2000

1. BACKGROUND

TransAlta Utilities Corporation (TransAlta) filed its 1996 Phase II application (the Application)with the Alberta Energy and Utilities Board (the Board) on June 30, 1998. The Board issuedDecision U99035 dated August 10, 1999 respecting TransAlta’s 1996 Phase II application. TheBoard directed TransAlta to refile its 1996 Phase II Application, on September 1, 1999,incorporating the Board’s findings in Decision U99035.

In Decision U99035, the Board noted that distribution rates (based on Old World generation costallocation methods) were in effect during 1996, 1997 and 1998. General rate riders, applicable toall rate classes, were agreed to in the 1997 and the 1998 Negotiated Settlements. In DecisionU99035, the Board deemed the interim rates in place from January 1, 1996 to December 31,1998 to be the final rates for that time period.

After alerting the Board that it would be unable to refile by September 1, 1999 TransAltaprovided its refiling on October 4, 1999. (TransAlta amended its refiling by letter dated October25, 1999.) In the refiling TransAlta proposed to implement a Direct Access Tariff (DAT) priceschedule, an Interest Refund Rider, and the Terms and Conditions (T&C) effective November 1,1999. TransAlta proposed that all other refiled rates would be effective February 1, 2000.

By letter dated October 13, 1999, the Board set out a process for examining the refiling. Theprocess (as revised by letter dated October 28, 1999) allowed time for information requests on allrefiling matters, requested that intervening parties provide any submissions on the refiling byNovember 22, 1999 and requested that TransAlta respond to any intervenor comments byNovember 29, 1999.

While the bulk of the submissions of various parties related to specific items of the refiling,substantial questions were also raised regarding the refiling process and the manner ofimplementing new rates.

In Decision U99105 dated November 3, 1999, the Board dealt with certain matters arising out ofDecision U99035 and subsequent submissions. The Board approved the T&C as proposed inTransAlta’s refiling on an interim, refundable basis effective November 1, 1999. The Board alsoapproved, on an interim refundable basis effective November 1, 1999, the DAT proposed byTransAlta in the refiling.

Separate from the refiling process, the Board also received the following formal applications toreview and vary (R&V) Decision U99035:

1. BACKGROUND TransAlta 1996—Phase II Refiling


• An October 13, 1999 Application (the LE/RD R&V Application) by Cities of Lethbridgeand Red Deer (LE/RD) and ENMAX Corporation for the R&V of Decision U99035.

• An October 29, 1999 Application (the SAREA R&V Application) by South AltaElectrification Association Limited (SAREA) for the R&V of Decision U99035.

• A November 8, 1999 Application (the CTMPN R&V Application) by the Chemi-ThermoMechanical Pulp & Newsprint Producers (CTMPN) for the R&V of DecisionU99035.

• A November 8, 1999 Application (the IPCAA R&V Application) by the Industrial PowerConsumers Association of Alberta (IPCAA)

In Decision U99105, dated November 3, 1999, the Board indicated that the two R&Vs receivedby the Board to that point in time (the LE/RD R&V and the SAREA R&V) were to be held inabeyance until after the Board issued this Decision on TransAlta’s refiling.

TransAlta 1996CCPhase II Refiling


2. THE PURPOSE OF THIS DECISION ON THE REFILING

In its order to TransAlta to refile its 1996 Phase II,1 the Board ordered TransAlta:

…to refile its proposed Rates and Options and its Terms and Conditions ofElectric Service, incorporating the findings of the Board in this decision toinclude a cost of service study incorporating the findings of the Board in thisDecision to include the revenue- to- cost ratios for each rate by cost source(Energy Supply, TA Billings and DISCO Services).

TransAlta requested that the new rates conforming to Decision U99035 be effective February 1,2000. Other parties raised the questions of whether the rates arising out of Decision U99035should be implemented February 1, 2000 and if not, what interim rates should be in effect andwhat further process should be followed.

The Public Institutional Consumers of Alberta (PICA), the Municipal Intervenors (MI), theConsumers Coalition of Alberta (CCA), the Independent Power Producers Society of Albertaand the Senior Petroleum Producers Association (IPPSA/SPPA), and the Alberta Federation ofREAs Ltd. and the Alberta Association of Municipal Districts and Counties (REA/AAMDC)submitted that the Board should approve the 1998 rates on an interim refundable basis effectiveFebruary 1, 2000. Changes flowing out of the 1999/2000 GTAs, any deferral accounts and theR&V Applications should be dealt with later. IPPSA/SPPA submitted that further delay was notappropriate; customers must see revised price signals representative of the significant changesthat have taken place in the Alberta electric industry.

The Chemi-ThermoMechanical Pulp and Newsprint Producers (CTMPN) opposed anyimplementation of the rates arising from Decision U99035. CTMPN submitted that there were nocompelling reasons to implement the rates with only 11 months until 2001, when some of theelements which support a deregulated marketplace are expected to be implemented. Interim rateswould result in significant negative cash flow changes that should not be incurred prior to anyfinal decision on the allocation of generation costs. Further, large, high load factor customerswould individually incur an economic hardship that is disproportionately higher than the benefitrealized by small, low load factor customers on an individual basis. Approval of interim rateswould be suggestive that the Board had reached a Decision on the energy based generation costbefore disposing of the issues raised in the R&V Applications.

CTMPN submitted that an oral hearing should be held to discuss the refiling, the rate increasesand the R&V applications. However, the CTMPN submitted that, if interim rates are to beapproved, existing rates should be made interim. Then, if the Board decides that the demandbased allocation of generation costs should continue, large, high load factor customers will nothave unnecessarily incurred electricity costs that would ultimately be refundable. The CTMPN

1 Decision U99035, p.184

2. THE PURPOSE OF THIS DECISION ON THE REFILING TransAlta 1996—Phase II Refiling


submitted that adoption of a cost allocation philosophy which is so damaging to high load factorindustrials during a transition period, when they don’t have price management tools which wouldotherwise be present in the market, will result in a more dramatic and unnecessary variance inelectric prices. The MI submitted that none of the reasons or remedies set out under the summary in CTMPN’ssubmission related directly to TransAlta’s refiling. The REA/AAMDC submitted that the issues raised by the CTMPN had been thoroughlycanvassed in the Phase II proceedings and should not be reopened except by an R&V applicationwhich passes the threshold test.

IPCAA also opposed interim implementation of the rates arising from Decision U99035. Ifinterim rates are to be approved, contrary to IPCAA’s recommendation then IPCAA submittedthat only the cost of service and not the rate design aspects of the energy-based allocation shouldbe implemented. IPCAA considered that this result could be achieved if TransAlta retained Rate790 (Large General Service) for Transmission Service customers and increased revenue byapplying a 10% Rider over that due under Rate 790 alone. The design of rates withinTransmission Service - Rate 6400 could be finalized applying the cost allocation principlesIPCAA advocated. The adoption of that approach would have no impact on other rate classes,but would allow the principles of cost allocation established in Decision U99035 to beimplemented to the rate class level so that they would be altered by future rate riders ifnecessary.

TransAlta submitted that CTMPN sought further delay and more Phase II proceedings.TransAlta stated that CTMPN sought to raise matters that were well beyond the bounds ofrefiling issues, and that amounted to requests to change the parameters of Decision U99035itself. TransAlta submitted that those requests should be rejected.

TransAlta noted that other requests in several forms had been made in intervenor submissions topostpone the effective date of the new rates and to reopen or institute new rate designproceedings. TransAlta submitted that such proposals would have the undesirable effect ofpostponing even further the already long-delayed redesign of existing rate structures which stillreflect 1992 parameters. TransAlta considered that delaying implementation of new rates wasinappropriate and that rates should be made final through January 31, 2000. If the R&Vapplications could not be disposed of before January 31, 2000 or the rate rider effects ofDecision U99099 were not determined before then, TransAlta submitted that new ratesconsistent with Decision U99035 could be made effective on an interim basis for February 1,2000. Whether final or interim, however, postponement of implementation for some indefiniteperiod beyond February 1, and perhaps right through 2000, was not appropriate in TransAlta’sview.



Several parties expressed views regarding the fairness of the refiling process. TransCanadaEnergy Ltd. (TransCanada) submitted that its interests and the interests of other parties had beenprejudiced by the process. TransCanada noted that the refiling process allowed no opportunity tocross-examine TransAlta in situations where TransAlta had not provided complete or accurateanswers. TransCanada submitted that using information requests without a hearing wasinadequate to ensure that a proper rate structure was put into effect for Rate 6400/6410(Transmission Service) customers. TransCanada stated that TransAlta’s rate increases are to besubstantially larger than for ATCO Electric Ltd. (AE). TransCanada submitted that in previousPhase II proceedings adjustments to the filings were relatively minor or quite mechanistic andthere was a reasonably low likelihood of a particular rate class ending up with refiled rates thatwere materially changed. TransCanada argued that parties have not had the chance to provideevidence and/or address the consequences of the re-allocation of generation costs. TransAlta’simplementation of Decision U99035 would lead to rate shock for large, high load factorcustomers. TransCanada supported IPCAA’s request to institute a 1999/2000 Phase II as apractical means to have these matters resolved.

Albchem Industries Ltd., CXY Chemicals and Dow Chemical Canada Inc. (ACD) submitted thatthe Directions in Decision U99035 have yielded very negative impacts on the ACD which werenot known when TransAlta’s Application was being considered nor obvious at the time DecisionU99035 was rendered. ACD stated that TransAlta refused to respond to ACD.TAU-4 andprovide the information to enable the Board to assess the magnitude of the change between therefiled rates and rates in TransAlta’s original Application. ACD submitted that they faced a hostof new issues arising from TransAlta’s refiling which they did not face and could not reasonablyhave anticipated or have been expected to address in the context of TransAlta’s Phase IIApplication as originally filed. TransAlta referred to the ambit of the refiling issues and its view that several intervenorsattempted to raise issues that went beyond the parameters of the refiling process. TransAltasubmitted that it had applied the Decision and the directions contained therein and in itsresponses to information requests had only declined to respond to matters at variance with theparameters of Decision U99035.

Several parties addressed how the Board should deal with substantive challenges to DecisionU99035 and the various formal R&Vs. The MI submitted that, as indicated by a November 24,1999 letter by ATCO Electric Ltd., there are two separate processes; one relating to“implementation” of the Board’s Decision and the other relating to a “challenge” of theDecision. The MI submitted that all R&V Applications should be left in abeyance until theexpiry of the 90-day limitation period. Issues, which are R&V related, should not influence theBoard’s Decision with respect to the refiling. The MI and several other parties suggested that itmight be appropriate for the CTMPN, the ACD and IPCAA’s R&Vs to be combined into oneR&V to avoid further duplication.



ACD submitted that there were new issues, which needed to be considered after parties had theopportunity to address evidence as to the merit of and the impact of cost allocation and ratedesign issues reflected in the rates proposed in the refiling. These issues, ACD submitted, werenot raised in the original Application. ACD suggested that “a revised process does not change the way or the reasons for which electriccosts in Alberta originated.” ACD pointed out that the “the Power Pool of Alberta and energymarkets had not, in 1998, developed to the point where they were able to differentiate as betweencustomers who have high load factors, between customers who have varying lengths of contractsor between customers that have other potentially more or less desirable pricing attributes.” The MI submitted that the ACD submissions amounted to R&V submissions and should be thesubject of a separate proceeding.

TransAlta submitted that ACD re-raised an issue that was extensively examined in the Phase IIproceedings (for example, Evidence on behalf of IPCAA by Drazen Consulting Group, Inc.,Exhibit 56, p.6-7). TransAlta further submitted that the Board had reviewed changes as to howthe DISCO incurs generation costs in Decision U99035.

TransAlta submitted that ACD did not recognize that the parameters of TransAlta’s originalPhase II filing have been overtaken by Decision U99035 and that ACD continued to seekcomparisons between the Refiling and the original Application. With respect, TransAltasubmitted that such comparisons were not issues in the Refiling approval process.

Board Findings

The Board considers that the submissions of parties, directed towards the refiling process and themanner of implementing new rates, raised several questions.

1) Was the process to examine the rates arising from the refiling fair and is a further processrequired before the rates arising from Decision U99035 are implemented?

2) How should the Board deal with the formal R&Vs, which were filed with the Board afterthe issuance of Decision U99035?

3) Should the Board consider a review and variance of Decision U99035 on its owninitiative based upon submissions on matters in the refiling?

4) Specifically, should the Board consider a review and variance of Decision U99035 on itsown initiative to delay the implementation of the rate design arising out of the Decisionuntil after the formal R&Vs are heard?



The Board will now deal with these questions as outlined above. The Board notes that thequestion regarding the fairness of the process to examine the rates, arising out of the refiling,centered around the completeness of TransAlta’s responses and the opportunity for intervenors tofully present a case. In regards to concerns regarding the completeness of TransAlta’s responses,the Board agrees with TransAlta that the refiling process requires only comparison of the refiledrates to the revenues from existing rates and not to the rates that TransAlta originally applied for.Several parties expressed concerns that the refiling process did not provide an opportunity tofully present their cases due to deficiencies in TransAlta’s responses. The Board has consideredthe question of the adequacy of information responses more fully in Section 17 of this Decision.The Board notes that parties (ACD, IPCAA, TransCanada and IPPSA/SPPA) were able togenerate the approximate increase in billings for the customers they represent to support the mainthrust of their rate shock arguments as addressed in Section 4 - Level of Rate Increases.

The Board further notes that while the Phase II refiling process primarily examined TransAlta’scompliance with Decision U99035, the Phase II proceeding itself had provided a forum todiscuss all matters arising out of any change to the generation allocation methodology from thehistoric methods including the impacts on customers. TransAlta proposed an energy basedallocation of the reservation payments (RP) not significantly different than that approved by theBoard in Decision U99035. Many intervenors used the Phase II proceeding to examine thosematters and to discuss the impacts of a change in allocation methodology on customer rates.

The Board is satisfied that, overall, the Phase II refiling process was sufficient and fair to parties.The process allowed parties to obtain the information needed to make and support their positionsin regard to the refiled rates as reflected in Section4 - Level of Rate Increases and Section 17 -Adequacy of Information Responses. The process was sufficient to allow the Board to make allof the necessary decisions on the refiling with a view to implementing the rates arising out of thisDecision. The Board considers that no further process is required other than a limited secondrefiling, a summary of which is described in Section 20 - Summary of Board Directions.

The purpose of this Decision is to determine whether TransAlta has complied with the Directionsand Orders of the Board given in Decision U99035, and to implement the rates and the Termsand Conditions of service arising out of the refilings. Decision U99035 required the energy basedallocation of generation costs. Subsequently, some parties objected and filed formal R&Vs.

The Board has already indicated in Decision U99105 that two R&V applications regardingDecision U99035 were to be held in abeyance until after the Board issued this Decision on thisTransAlta refiling. The Board considers that the Phase II proceeding and the Phase II refilingprocess provided a fair and adequate means of examining the relevant matters needed to beconsidered so as to implement new rates. Nevertheless, the Board recognizes that certain partiesfeel compelled to challenge aspects of Decision U99035 through the R&V process. However,these R&V applications must be conducted with due process, including adequate public notice.These R&V applications can most fairly and effectively be dealt with after the final Phase II



decision is rendered. Therefore, the Board will hold all the formal R&V applications, regardingDecision U99035, in abeyance until after issuance of this Decision on the refiled rates.

However, the Board considers that in the refiling process a number of parties, includingTransAlta, have essentially requested that the Board review and vary Decision U99035 on theBoard’s own initiative after consideration of the submissions that the Board has received in therefiling process.

The Board considers that the examination of certain aspects of those requests made within theforum of the refiling process would be an efficient and fair use of the refiling process. Therefore,in the following sections of this Decision, the Board will also consider whether to review andvary Decision U99035, on its own initiative, based on the information responses, writtensubmissions, and reply submissions provided in the refiling process and in the Phase II record.

The Board notes that any variance of Decision U99035 that it makes in this Decision is subject tosection 51 of the Public Utilities Board Act (PUB Act) and is without prejudice to the rights ofany party to its formal R&V application.

One issue that the Board was requested to review and vary on its own initiative was theimplementation of the rates arising out of Decision U99035. Some industrial submissionsrecommended that the rates arising out of Decision U99035 not be implemented until after theR&Vs were decided upon or after a 1999/2000 Phase II was held. Such an approach wouldrequire the Board to delay the implementation of the redesigned rates for at least several months.Since this would essentially make academic other issues to be considered in this refilingDecision, the Board considers that the implementation question should be addressed initially.Therefore, the Board will address the matter in this section.

The Board considers that the implementation of new rates should not be based on the self-interests of the various parties. New rates should be implemented on the basis of thedeterminations the Board has made, after an analysis of the way in which the Electric UtilitiesAct (the EU Act) restructured the industry. That analysis occurred in the Phase II proceeding.

The passage of the EU Act initiated the restructuring of electric tariffs. Key provisions of theEU Act are the establishment of an open access Power Pool, in which all electricity is traded, thefunctional separation of the integrated utilities for accounting and regulatory purposes, theestablishment of a single Transmission entity, and the implementation of legislated hedges.

In the Phase 1 Decision U97065, dated October 31, 1997, the Board carried out a comprehensivereview of utility revenues and costs for 1996. That Decision was intended to ensure that the faircosts of service, consistent with the cost characteristics of the restructured industry, wouldcontinue to be recovered by the utilities in the province. The Board provided specific directionsto the utilities to achieve that objective.



In Decision U99035, the Board noted that distribution rates (based on Old World generation costallocation methods) were in effect during 1996, 1997 and 1998. General rate riders, applicable toall rate classes, were agreed to in the 1997 and the 1998 Negotiated Settlements. In DecisionU99035, the Board deemed the interim rates in place from January 1, 1996 to December 31,1998 to be the final rates for that time period.

The interim rates in place during 1996 to 1998 were based on the pre-EU Act rate design criteriathat were used in 1992. Those rates did not reflect the existence of the Power Pool, legislatedhedges, or the transmission administrator. In Decision U99035, the Board set out the principlesfor rates that would appropriately collect, from customers, the costs that customers causeTransAlta’s DISCO to incur in the restructured industry.

The Board considers that the existing rates do not reflect the cost characteristics of therestructured industry. The Board considers that customers should see revised price signalsrepresentative of restructured industry without further delay.

The Board cannot justify leaving in place rates that were designed to be appropriate in 1992 andwere only appropriate for the situation existing prior to industry restructuring. Those rates weredesigned for 1992 and reflect the fact that, prior to 1996, high load factor customers reduced perkWh system generation costs through these customers’ ability to be interrupted and through theirload shape. Under those 1992 rates, high load factor customers benefit through credits forinterruptibility, through low run out energy costs, and through demand based allocation ofgenerating costs.

The Board explained in Decision U99035 that, since 1996, the entire cost to the DISCO toprovide incremental energy, regardless of load factor, has been the pool price. The Boardrejected demand based allocation of hedges since “The demand based allocation methods wouldhave given some customer classes a greater share of, or right to the net benefits of the legislatedhedges, even though the DISCOs incur the same cost, the pool price, for incremental energy.”Therefore, in the Decision, the Board accepted that, to be fair to new and existing customers, theenergy allocation method should be used stating that:

The Board considers that the H factor will provide the fair allocation, required bythe EU Act, of the value and cost of the legislated hedges among all future usersof electric energy in Alberta. The demand based allocation methods would havegiven some customer classes a greater share of, or right to the net benefits of thelegislated hedges, even though the DISCOs incur the same cost, the pool price, forincremental energy to serve customers in any class.2

2 p.26-20



The Board also recognized in Decision U990353 that the energy market is not necessarily perfect(as some parties noted in their refiling submissions). The Board accepted that the DISCOs wouldhave to buy incremental power at the pool price for any type of actual customer load, regardlesswhether the customer has a high or a low load factor. The Board did not try to emulate or modela competitive market or anticipate future energy costs or hedge values after 2001, as some partieshave suggested. Instead, the Board merely attempted to pass through, to every load served, theincremental charges actually paid by the DISCO to serve any incremental load during thetransition to deregulation. These charges include the Power Pool charges and the TA charges.

One cost the DISCO faces to serve any incremental load is the TA charges that the load causesthe DISCO to incur. The Board attempted to pass the TA charges through to the customers whocaused the DISCO to incur them. The forecast TA charges were based on actual 1998 TAbillings adjusted to reflect the TA rates in effect in 1999. Actual TA charges were to be passedthrough to every customer served at 25kV or higher who is the only customer at a point ofdelivery.

Another cost the DISCO faces to serve incremental load is the pool price, a market price that theDISCO pays to the Power Pool for all the energy it requires in a given hour. The Boardattempted to pass the Power Pool charges through to the customers who caused the DISCO toincur them. For fixed rate classes, the forecast pool purchase costs (the actual 1998 hourly classload times hourly pool price summed over all the hours in 1998 for each rate class) wereassigned to that rate class.

The Board developed an allocation of the RP and the Unit Obligation Value (UOV) refundwhich, while fair to existing and new customers in every class,4 also allowed the hourly variationin the pool price to be passed through to those customers who wished to see it.

Therefore, the Board considers that the refiled rates will reflect the basic realities of DISCO costsin the transition to 2001, once the relatively minor changes outlined in this Decision are made.The Board considers that the new rates, which arise out of this Decision, will be fair and providebetter signals of the generation and transmission costs that DISCOs incur. The new rates reflectthe costs to serve the DISCO’s customers during the transition and are more appropriate than theexisting rates, which are based on the 1992 test year and pre-1996 demand allocation methods.Further, the new rates will set out a framework, which lends itself to both the current restructuredelectric industry in Alberta and the post-2000 deregulated world.

The Board has noted customer concerns over the extent of changes in this transition toderegulation. The Board in Decision U99035, implemented a 10% cap in the increase for anyrate class. In Section 4 - Level of Rate Increases, in this Decision, the Board examined whether

3 p.194 Decision U99035, p.20



the size of the rate increases and uncertainty of other costs /credits arising in the transition shouldlead to caps for certain customers.

After consideration of the analysis in that Section, the Board is not convinced that the amount ofthe cost increases to individual customers or rate classes should cause the Board to delayimplementing the more appropriate rate structure. Similarly, the Board considers that the ratesarising out of this Decision are fair and do not result in undue discrimination to any customer.

For all of the foregoing reasons, the Board concludes that a delay in implementing the ratesarising out of Decision U99035 and this refiling Decision would be unacceptable and, therefore,the rates arising out of this Decision should be implemented as soon as possible. Accordingly,the Board will not review and vary Decision U99035 on its own initiative so as to avoid a delayin the implementation of the rate design arising from the Decision.

In the sections that follow, the Board will deal with the significant matters raised with respect tothe refiling, with a mind to implementing the rates which appropriately arise out of DecisionU99035.



3. ADJUSTMENTS TO THE REFILED COST OF SERVICE STUDY

In a letter dated August 30, 1999, TransAlta proposed to modify Direction 16. Direction 16required TransAlta to use the 1998 negotiated settlement revenue requirement approved inDecision U98093 in the refiled cost of service study. TransAlta was to calculate its Distributioncosts as a residual by subtracting Energy Supply Costs (using 1998 actual pool payments andobligation refunds) and TA Billings Costs (applying 1999 TA tariffs to actual 1998 transmissionloads) from that 1998 revenue requirement.

Instead of using the 1998 negotiated settlement revenue requirement, TransAlta has used theactual 1998 revenues. TransAlta calculated its Distribution costs as a residual by subtractingGeneration costs (using 1998 actual pool payments and obligation refunds) and Transmissioncosts (applying 1999 TA tariffs to actual 1998 transmission loads) from its actual 1998 revenuesas shown hereunder:

TransAlta Calculated Distribution Residuals ($ 000s)

Actual 1998 Utility Revenues $1, 124, 633 Less: Generation Costs (654, 620)Less: Transmission Costs (240, 736)Equals: Residual – Distribution Costs 229, 277

Certain parties suggested changes should be made to the 1998 actual costs and credits in the costof service study to make it a fairer representation of the costs to serve customers in each class.

IPCAA submitted that it had identified a number of other errors in the TransAlta re-filing andhad provided revised Cost of Service Tables to correct them.

IPCAA submitted that the TransAlta refiling makes use of an inappropriate reservation price(RP) to reflect 1998 actual costs. For 1998, IPCAA submitted that customers negotiated the RPsreflected in the negotiated settlements inclusive of the “loose juice” deferral accounts. Further,IPCAA stated that settlement of the customers’ portion of those deferral accounts is part of the1998 actual RP. IPCAA questioned what cash payments TransAlta actually made in respect ofRPs in 1998. IPCAA also identified that the 1998 negotiated settlement, with TransAlta,provided for the deferral accounts to be flowed-through to customers in the 1999 RPs. IPCAAstated that these are all issues related to cash flow and are not recognition of appropriate costs forthe 1998 period.

IPCAA noted that in response to IPCAA-AEL-3, AE indicated it had incorporated the “loosejuice” deferral accounts in addition to the amounts related to the Battle River 1 and 2 generatingunits in calculating “actual” 1998 RPs. IPCAA submitted that AE “got it right.”

3. ADJUSTMENTS TOTHE REFILED COST OFSERVICE STUDY

TransAlta 1996—Phase II Refiling


In contrast, in response to IPCAA.TAU-3, TransAlta infers that actual RP are part of the “actual1998 pool price record” and that its approach was mandated by Decision U99035.

IPCAA submitted that there was nothing in Decision U99035 suggesting the RPs made on a cashbasis rather than as accrued for 1998 were the appropriate amounts to recognize in the re-filing.For items settled on an hourly basis, such as pool purchases and UOV refunds, there areessentially no differences between the cash or accrual basis (except for after-the-fact corrections)whereas RP can be significantly different on a cash or accrual basis.

IPCAA submitted that the accrual approach should be adopted in these circumstances andprovided the following Table to determine the correct 1998 RP.

IPCAA’s Correction to the 1998 RP (TransAlta)1998 RP $ millionsTransAlta 523.9EPCOR 268.5ATCO 263.5Subtotal before Deferral Accounts 1,055.9

Less “Loose Juice” Deferral Accounts -29.2Net of “Loose Juice” Deferral Accounts 1,026.7Less Battle River 1 & 2 ($0.55 m per mo.) -2.8Less Battle River 1 & 2 (one time reduction) -3.7Net Total RP 1,020.2

TransAlta Disco RP Share 42.910%

TransAlta’s RP before Deferral Accounts 453.1Less “Loose Juice” Deferral Accounts -12.6Net of “Loose Juice” Deferral Accounts 440.5Less Battle River 1&2 (monthly amount.) -1.2Less Battle River 1&2 (monthly amount.) -1.6Net TransAlta Disco Total RP $437.8

IPCAA noted that TransAlta also identified $9.97 million of adjustments to Power Poolpurchases5 of which $5.6 million ($4.244 million - $0.575 million + $1.994 million) appear to beadjustments for periods other than 1998. IPCAA submitted that TransAlta should remove theadjustments for prior periods and recalculate the Pool Price charges in all tariffs. IPCAAcalculated that the effect should be to reduce energy charges by $0.24/MWh on average ($5.6million/23,600 GWh).

5 IPCAA.TAU-3




IPCAA also submitted that TransAlta revenue calculations incorporated a simplistic calculationof Planned Interruption Option F and Planned Interruption Transition Alternative Option Gcredits for the year 20006 and should be adjusted. First, the calculations contain arithmetic errorsresulting in $0.6 million being allocated across all rate classes rather than only the rate classesincluding Option F customers. (IPCAA.TAU-11: $5.717 million x (3/4 – 2/3) + $4.292 million x(3/4 – 2/3) x 20%/50%).

Second, the amounts are not consistent with those TransAlta filed in the recent 1999/2000 PhaseI proceeding. IPCAA submitted that the calculation fails to recognize that some Option 12contracts expire prior to August 31, 2000 and that TransAlta overstates the amount of credits tobe paid by $1.575 million relative to the amount in the Phase I filing which should be used in therefiling. The updated Option F and G credit amounts are incorporated in revenue calculations inTables Rates A-1.0 Refiling IPCAA and Rates A-2.0 Refiling IPCAA and in the adjusted cost ofservice calculations in Tables Rates A-3.0 Refiling IPCAA.

IPPSA/SPPA submitted that the Board should direct TransAlta to adjust its rates to correct forthe errors identified in IPPSA/SPPA.TAU-5(c) and IPCAA.TAU-11(b) and (f).

The MI submitted that other parties have not had the opportunity to fully consider and test thematters addressed in IPCAA’s revised cost of service and rate design within the refiling process.The REA/AAMDC noted that, while they had not reviewed the adjustments proposed by IPCAAin any great detail, some appeared to have merit.

TransAlta submitted that the errors identified in IPPSA/SPPA.TAU-5(c) and IPCAA.TAU-11(b)and (f) were not material.

TransAlta responded to IPCAA’s submission that RPs, as accrued for 1998, are appropriaterather than those made on a cash basis. TransAlta noted that: “The Board also directs TransAltato use the fixed amount “H” charge calculated using the 1998 pool price record and total 1998TransAlta DISCO annual energy usage.”7 TransAlta submitted that the “H” charge includes onlycosts related to RP and UOV refunds. Consequently, TransAlta found it difficult to interpret theDirection as anything but requiring the use of the actual amounts recorded as paid to the PowerPool in 1998 in respect of RP and obligation value refunds.

TransAlta contended that, in contrast, IPCAA calculated a reduced RP by accruing for thesettlement of so-called “loose juice” deferral accounts, which had not yet occurred in 1998. InTable COS A-1.0 Refiling IPCAA, the reduced RP is then incorporated in IPCAA’sdetermination of the Total Cost of Distribution (Column F) using the residual method as directedby the Board. TransAlta submitted that if the Board determines TransAlta should reduce its 1998

6 IPCAA.TAU-117 Decision U99035, p.53




RP below the amount actually paid by TransAlta in 1998, such reduction should not thenincrease TransAlta’s cost of distribution through the use of the residual calculation.

TransAlta understands the principal reason for using the residual method to determinedistribution costs is to reflect the reclassification of 25 kV facilities from distribution totransmission under the Electric Utilities Amendment Act of April 30, 1998. The Board directedTransAlta to “reflect the 1999 TA rates which are adjusted for the effect of reallocating the25 kV plant to transmission.”8 The Board correspondingly directed TransAlta “to prorate the1996 distribution cost allocations (as adjusted for the removal of the 25 kV costs fromdistribution) in the Application to the 1998 residual in the refiling.”9 TransAlta concurred that,when combined with the use of TransAlta’s actual 1998 distribution revenue as submitted in itsrefiling, the “residual” will reasonably approximate the 1998 cost of distribution that would havebeen incurred had the 25 kV distribution facilities been reclassified to transmission for the wholeof the year.

TransAlta also submitted that any adjustments to energy supply costs to accrue for costs incurredin other years should not affect the amount of the distribution “residual.” The residual wascalculated as actual 1998 revenues less costs of purchasing energy supply and less costs ofpurchasing transmission services using the TA’s interim 1999 rates. Any adjustments to energysupply costs should also be made to 1998 revenues, and then be appropriately reflected for allrate classes in riders related to revenue requirements for 1999 and 2000.

TransAlta further submitted that if adjustments to energy supply costs are included in thecalculation of the “residual,” such adjustments will distort the distribution costs included in theRefiling and move away from the reasonable approximation already provided by the Board’sresidual method.

TransAlta noted that IPCAA referred to “a number of other errors in the TransAlta re-filing” andincludes revised Cost of Service Tables as Appendix C correcting the so-called “errors.”10

TransAlta pointed out that the tables in IPCAA’s Appendix C contain a single change comparedto those in TransAlta’s Refiling, that change being the reduction in 1998 RP corresponding toIPCAA’s calculation on page 9 of its submission. No other changes appear in the cost of servicetables in IPCAA’s Appendix C (although several are included in the rate tables in IPCAA’sAppendix B).

TransAlta also responded to IPCAA’s and IPPSA/SPPA’s submission on the calculation of theOption F and G credits under proposed rates. The credits in 1998 were $5.717 million for Option12/F and $4.292 million for Option 21/G, for a total of $10.009 million. 11 Under proposed rates,

8 Decision U99035, p.539 p.5410 Submission of IPCAA, p.711 IPCAA.TAU-9




TransAlta reduced these amounts to $4.288 million and $1.287 million for a total of $5.575million, to reflect the fact that the credits expire on August 31, 2000. TransAlta argued against IPCAA claims that the $5.575 million was overstated by $1.575million and argued against IPCAA’s recommendation to reduce the amount to that used in thePhase I forecast. TransAlta submitted that its calculation error12 in using the factor 2/3 instead of¾ was not material. IPCAA was again proposing to make selective use of (Phase I) forecast datarather than actual data, when this Phase II should properly be based consistently on 1998 actualloads, prices and revenues. TransAlta would recommend that the Board not adjust the amounts tothe Phase I forecast. TransAlta recommended that the Board resist all attempts to make selective adjustments to 1998actual revenues.

Board Findings

In Decision U99035, to set out how TransAlta should calculate its costs in its refiled cost ofservice study, the Board made the following directions:

The Board directs TransAlta to apply its actual metered class hourly load to theactual 1998 hourly pool price record to determine a more appropriate annualaverage cost of energy for each fixed rate class. Similarly, the Board directsTransAlta to use the average actual pool price in each TOU period in 1998 as thecost of energy components in the TOU rates. The Board also directs TransAlta touse the fixed amount “H” charge calculated using the 1998 pool price record andtotal 1998 TransAlta DISCO annual energy usage. This approach will, in theBoard’s view, provide appropriate levels for each class’s annual average cost ofenergy and TransAlta’s “H” component.

The Board directs TransAlta to use the TA’s interim 1999 rates (as approved inOrder U99018 dated 11 February 1999) and TransAlta DISCO’s actual 1998 TAinvoiced kWh and kW to determine updated TA Billings. The allocation to rateclasses and transmission served customer classes should use actual 1998 hourlyclass load and NCP data to determine the kWh and kW charges.

Therefore, the Board considers that it is appropriate that the costs used in the cost of servicestudy should be the actual net costs that were incurred by TransAlta’s DISCO to serve customersin 1998. The actual net costs should be consistent with the actual metered class hourly load, theactual TA invoiced kWh and kW, and the actual 1998 pool price record.

12 As noted in IPCAA.TAU-11




Therefore, the Board agrees with IPCAA that energy supply cost amounts paid out that reflectpast year adjustments would not have been incurred by TransAlta to serve customers in 1998.

In the case of the net value of the legislated hedges used to calculate the H component, the Boardnotes that, while the entitlement value that TransAlta used does reflect the 1998 actual pool pricerecord, the level of the surplus/shortfall in TransAlta 1998 RP payments does not. It was basedupon forecast pool prices. The Board considers that the forecast surplus/shortfall inherent inTransAlta’s 1998 RP should be adjusted to reflect the DISCO’s share of the actualsurplus/shortfall deferral accounts that was based on actual pool prices and loads. The Board alsoconsiders that the adjustments for Battle River are appropriate in the determination of theappropriate level of the RP in the actual net costs incurred by TransAlta to serve customers in1998. The Board considers that using the above methodology will result in the actual net coststhat were incurred by TransAlta’s DISCO to serve customers in 1998 being matched to the actualmetered class hourly load, the actual TA invoiced kWh and kW, and the actual 1998 pool pricerecord.

This ensures compliance with the directions in Decision U99035 that dealt with how to calculatethe updated 1998 forecast costs of Energy Supply and the updated TA Billings. The Board alsodirected TransAlta to deduct the resulting costs of Energy Supply and the updated TA Billingsfrom TransAlta DISCO’s 1998 negotiated revenue requirement and to use the resulting 1998residual as the cost of TransAlta’s DISCO Services in the refiling. The Board noted that thatapproach will keep the price signals from the Energy Supply and TA Billings cost sourcesaccurate, while allowing TransAlta to recover the 1998 DISCO revenue requirement negotiatedwith its customers.

In the refiling, instead of using the 1998 DISCO negotiated revenue requirement, TransAlta usedthe actual 1998 revenues of the DISCO. TransAlta explained that the actual 1998 revenues wereused to obtain the 1998 distribution costs, by subtracting the actual 1998 generation costs andsubtracting transmission costs based on 1998 billing determinants and 1999 EAL tariffs.TransAlta noted that this approach ensured that the tariffs included in the refiling would haveyielded the same revenue in 1998 as was actually collected and provided a reasonableapproximation of actual 1998 distribution costs.

The Board notes that TransAlta submitted that changes in the RP and changes in the energysupply costs to reflect prior period adjustments should also result in a similar decrease in the1998 revenue requirement. TransAlta pointed out that if adjustments to Energy Supply costs areincluded in the calculation of the residual, such adjustments will distort the distribution costsincluded in the refiling and move away from the reasonable approximation already provided bythe Board’s residual method. TransAlta submitted that the decrease was necessary to keepdistribution costs calculated by the residual method a reasonable approximation of the actual1998 distribution costs. The Board agrees that it is desirable to maintain the distribution costused in the cost of service study at a reasonable approximation of actual 1998 distribution costs.Therefore, the Board agrees that TransAlta should also reduce its total 1998 cost of service to




reflect the reductions so that there is no increase in TransAlta’s cost of distribution arising fromthe changes in the RP and energy supply costs.

The Board also considers that the errors which TransAlta acknowledged that it made in its costsof service study as identified in IPPSA/SPPA.TAU-5(c) and IPCAA.TAU-11(b) and (f) shouldbe corrected.

Accordingly, the Board directs TransAlta to redo, in a second refiling, its cost of service studyimplementing the changes below:

• TransAlta’s 1998 RP and total cost of service should be reduced to reflect the DISCO’sshare of the actual surplus/shortfall deferral accounts that was based on actual pool pricesand loads

• TransAlta’s 1998 RP and total cost of service should be reduced to reflect theadjustments for Battle River

• TransAlta’s 1998 energy supply cost and total cost of service should be reduced by theamounts paid out that reflect prior year adjustments

• TransAlta should correct the errors identified in IPPSA/SPPA.TAU-5(c) andIPCAA.TAU-11(b) and (f)

The Board also directs TransAlta to change, in a second refiling, the refiled rates as necessary toallow these rates to reflect the new cost of service study, Decision U99035, and this Decision.

With respect to the changes IPCAA and IPPSA/SPPA proposed to the level of the option F andG credits, the Board agrees with TransAlta that IPCAA is proposing to make selective use of(Phase I) forecast data rather than actual data. Therefore, the Board does not consider itappropriate to require TransAlta to make the adjustment to option F and G credits that IPCCAhad recommended.



4. LEVEL OF RATE INCREASES

A number of submissions dealt with the level of the increases to be seen by customers due to thedirections in Decision U99035. Parties questioned which base the 10% increase should beapplied to and whether there should be a variance to Decision U99035 to allow the increase toapply to subsets of the rate classes or to individual customers.

In U99035 the Board indicated the following:

To ensure some degree of rate stability in moving to accurate cost signals, theBoard directs that in the refiling, the DISCO keep the overall increase in revenuearising from the rate redesign at less than 10% for any rate class. The revenue-to-cost ratio for both the Energy Supply and TA Billings components of each rateshould be moved to exactly 100%, with the DISCO Services component (which isa residual) adjusted to ensure the overall increase in revenue is less than 10% forevery rate class. The Board notes that individual customers may see more than a10% increase if their usage characteristics warrant.

In the designing the refiled rates TransAlta applied a 10% cap based on the 1998 actual rate classrevenues.

(a) What Base Should the 10% Cap Be Applied To?

IPCAA submitted that some of its members have analyzed the TransAlta re-filed rates anddetermined that the proposed rates would result in increases to them of approximately 20% asconfirmed from their TransAlta sales representatives. For example, the increase to theTransmission Service rate class (Rate 6400) would appear to exceed 14% and it would seem thatthe additional four per cent increase is largely the result of TransAlta’s treatment of 1998“actual” revenue.

IPCAA submitted that Planned Interruption Transition Alternative Option 21 customers were tobe kept revenue neutral to Large General Service Rate 790 and the generation access charge (theGAC) was the mechanism that was intended to ensure that result. However, for 1998, the GACwas determined on a forecast basis, based on a forecast Pool Price of $24.2/MWh. In otherwords, if the 1998 Pool Price were to equal the forecast $24.2/MWh then the Option 21customers would be revenue neutral to Rate 790. Since the Pool Price exceeded the forecast theOption 21 customers paid more than they would have under Rate 790.

The customers knew that TransAlta’s forecast of 1998 Pool Price of $24.2/MWh was too low,but there was no forum in which to address it. In the 1998 negotiated settlement, the GAC wasset to zero for the last six months of 1998. This was not a perfect solution but it was the best that

4. LEVEL OF RATE INCREASES TransAlta 1996—Phase II Refiling


could be achieved at the time. For January 1999, TransAlta introduced a monthly GAC whichwas adjusted to reflect the actual Pool Price.

For the first six months of 1998, TransAlta applied the GAC as a charge of $0.90/kW per month;an amount that would have kept Option 21 customers’ revenue neutral to Rate 790 assuming aPool Price of $24.2/MWh. The actual Pool Price over that period exceeded $30/MWh with theresult that a GAC credit of $2.94/kW per month would have been required to keep Option 21customers revenue neutral to Rate 790. Over the second half of the year, the GAC was set at$0.00/kW per month; an amount that would have kept Option 21 customers revenue neutral torate 790 assuming a Pool Price of $25.6/MWh. The actual Pool Price over the last six monthswas $35.5/MWh. A GAC credit of $6.62/kW per month would have been required to keep theOption 21 customers revenue neutral to Rate 790 during that period.

Overall, as shown in the Table below, a GAC mechanism that would have kept Option 21customers revenue neutral to standard rates in 1998 would have resulted in net payments to themof approximately $14.1 million (rather than charges of $1.4 million) over 1998 actuals. Statedanother way, had the Option 21 customers instead been on standard rates in 1998, TransAltaDISCO would not have received the excess revenues of $15.5 million.

IPCAA’s Analysis of 1998 Excess Option 21 Revenue

Actual “Correct” Difference1998

ActualPool Price

ActualGAC

$/kW-mo.

“Correct”GAC

$/kW-mo.

DifferenceGAC

$/kW-mo.

EstimatedOption 21

kW

GACPayments $ 000’s

GACPayments $ 000’s

In GACPayment$ 000’s

Jan 27.20 0.90 -0.97 1.87 257,000 $ 231 $ (250) $ 481Feb 21.56 0.90 2.55 -1.65 257,000 231 654 (423)Mar 27.97 0.90 -1.45 2.35 257,000 231 (373) 604Apr 31.09 0.90 -3.40 4.30 257,000 231 (873) 1,104 May 32.19 0.90 -4.08 4.98 257,000 231 (1,049) 1,280Jun 42.10 0.90 -10.26 11.16 257,000 231 (2,637) 2,869Jul 29.04 0.00 -2.12 2.12 257,000 0 (545) 545Aug 33.27 0.00 -4.76 4.76 257,000 0 (1,223) 1,223Sep 36.14 0.00 -6.54 6.54 257,000 0 (1,682) 1,682Oct 48.27 0.00 -14.11 14.11 257,000 0 (3,626) 3,626Nov 34.06 0.00 -5.25 5.25 257,000 0 (1,349) 1,349Dec 32.65 0.00 -4.37 4.37 257,000 0 (1,122) 1,122

$1,388 $(14,075) $15,462 Option 21 load from 1996 GRA Phase II, IPCAA.TAU-37(g)

TransAlta has used 1998 actual revenues, which include the $15.5 million overpayment byOption 21 customers, as the starting point for its calculation of rate increases resulting from its



re-filed rates. IPCAA submitted that such an approach is inappropriate and the proper approachwould be to use forecast revenues assuming Option 21 customers to be revenue neutral to Rate790.

The TransAlta August 30, 1999 letter to the Board did not describe how the company intended totreat revenue from Option 21 customers. Similarly, the “response” to IPCAA.TAU-8 states:

TransAlta used 1998 revenues for the October 4, 1999 Refiling, as directed by theBoard. Estimates of what customers would have paid had they been on differentrates and options are beyond the parameters of the Refiling.

TransAlta’s refusal to provide information as to what forecast revenue on Option 21 would havebeen, leaves the Association in the position of having to estimate the payment that would havekept Option 21 customers revenue neutral to Rate 790. The table below provides such anestimate of the excess revenue, by rate class. As the actual billing determinants were notprovided by TransAlta, it has been assumed that the split of billing determinants would be equalto the split of option credits paid.

IPCAA’S ANALYSIS OF EXCESS OPTION 21 REVENUE BY RATE CLASS

Option 21Credits $ 000 Split %

EstimatedSplit

Option 21Load kW

EstimatedSplit Excess

Revenue $ 000

Option 21 Credits6100 - General Service $ 170 13% 33,947 $ 2,0426300 - Large General Service 67 5% 13,379 8056400 - Transmission Service $ 1,050 82% 209,674 $ 12,615

$ 1,287 00% 257,000 $ 15,462

Option 21 credits from Table Rates A-5.3 Refiling, October 4, 1998

The GAC excess revenue in 1998 represented a 25% increase in cost over standard rates for Rate6400 Option 21 customers.13 That is, in 1998 these customers saw a 25% increase in their cost ofpower due to a flawed GAC mechanism. Spread over all of Rate 6400, the $12.6 million ofexcess revenue represents a four per cent increase over existing rates (12.6/(323.7-12.6) = 4.4%).Thus, with the addition of the maximum 10% increase the total increase to the rate class exceeds14%, as shown in the table below.

13 See calculation Appendix A



IPCAA’s Analysis: Rate 6400 Rate Impact Recognizing Excess 1998 Option 21 Revenue

Revenue UnderExisting Rates

$ 000

Revenue UnderProposed Rates

$ 000Change

%

Transmission Service Revenue $ 323,673 $ 355,988 9.98%

Less: Excess 1998 Option 21 Revenue (12,615)

1998 Revenue on Standard Rates $ 311,058 $ 355,988 14.44%

This understates the increase as the Revenue Under proposed Rates overstates Option F/Gcredits to be paid

Revenue from Table Rates A-1.0 Refiling, October 4, 1999

IPCAA submitted that the impact of the $12.6 million over the entire rate class was important fortwo reasons. First, for the Transmission Service rate class, TransAlta is calculating the ten percent increase in proposed rates (over actual 1998 revenue) for the rate class from a starting pointof a four per cent increase in 1998 actual revenue over forecast revenue. Second, it is not at allfair or reasonable that a flawed GAC mechanism that was in place for 1998 should result in anadditional four per cent rate increase for non-Option 21 customers in the same rate class.

IPCAA submitted that when the effect of the excess Option 21 revenue is recognized, it becomesobvious why so many customers expect the re-filed tariffs to increase their charges by 20%notwithstanding the assertion by TransAlta that the average increase for the rate class is 10%. Tobegin, the average increase for Rate 6400 is 14% and not 10% versus standard rates. Second,TransAlta’s approach portrays Option 21 customers as receiving a rate decrease of 12.5%14 butthat only comes from the correction of the GAC mechanism to make customers revenue neutralto standard rates. Option 21 customers together represent approximately 15% of the rate class.15

If Option 21 customers are to receive a 12.5% rate decrease, then the remaining 85% of the rateclass will be subject to roughly a 19% increase in order that the increase for the rate classaverage 14.4% [(14.4%-(15% x –12.5%))/85]. Of course, Option 21 customers are not in factseeing a decrease. Rather, on a forecast basis they are seeing the same increase as the othercustomers in the Rate 6400 rate class.

14 IPCAA Submission15 IPCAA Submission, Appendix A



In contrast to TransAlta, IPCAA noted that AE has based its revenue calculation for Pool AccessRate (PAR) customers on what the billings would have been on standard rates rather than onactual revenues.16

IPCAA submitted that, for all of the reasons outlined above, the TransAlta re-filed rates do notcomply with the directions of the Board in Decision U99035. Accordingly, TAU should bedirected to revise the Transmission Service rates by (i) recalculating the revenue from Option 21customers using actual billing determinants from 1998; and (ii) applying the standard tariffs thatwere in place at the time. This will result in a revenue which is approximately $15 million lowerthan the re-filing. Alternatively, the $15.5 million that is calculated as being excess revenue canreduce the actual revenue. This would result in a revenue which is $15.5 million lower than theactual 1998 revenue. The estimated split, by rate class was presented above.

IPCAA noted that if the Option 21 customers had been on standard rates, the total revenue wouldhave been $15.5 million lower than was filed and the revenue from the proposed rates would be1.54% higher than the revenue on the existing rates. Table rates A-1.0 supplement RefilingIPCAA calculates the revenue increases assuming an across-the-board rider is used to provideequal revenue from both the existing rates and the proposed rates.

The CTMPN supported IPCAA’s position that the GAC mechanism was flawed and resulted inTransAlta receiving revenues in excess of those intended in 1998.

IPSAA/SPPA noted that the actual 1998 revenue, used to determine the maximum rate increaseper class, used a GAC of 0 for most of 1998. Therefore the GAC was higher in 1998 than itwould have been if the GAC were applied as it was in 1999 and will be until August 2000.IPSAA/SPPA submitted that the 1998 actual revenue numbers should be adjusted to reflect fullGAC credit in the determination of the amount of the rate increase for industrial customers.

The MI noted that, in TransAlta’s original Phase II filing, TransAlta indicated that the proposedtariffs should replace the interim rates including the EEMA Flow-through Rider approvedJanuary 1, 1996 in Order E95123 and the interim (6.9%) Rate Reduction Rider effective June 1,1998 as approved by Order U98093. However, in Table Rates A-2.0 of the Phase II Application,the proposed changes in rates were shown relative to the rates existing in January 1996. The MIsubmitted that the 10% maximum increase the Board directed was relative to the January 1996rates, otherwise the net cap would have effectively been 3.1%.

In contrast, TransAlta applied the 10% cap to the 1998 revenues in the refiling. Therefore, acustomer or rate class receiving the maximum 10% rate increase, will only receive a net increaseof 3.1% over January 1996 rates since the 6.9% reduction rider was in effect in 1998.

16 IPCAA-AEL-7



The MI submitted that all submissions that object to increases in excess of 10% should beviewed in that light. The MI also noted that the Board made it clear in Decision U99035 thatsome individual customers could expect increases in excess of 10% if their usage characteristicswarranted.

In response to IPPSA/SPPA requests for billing determinants under existing rates, TransAltanoted that revenue under existing rates was derived from actual recorded 1998 revenues by rateclass, and was not calculated from billing determinants. TransAlta submitted that billingdeterminants for existing rates were not required and were not produced for the October 4, 1999Refiling. Further, in IPCAA.TAU-12 TransAlta indicated that considerable analytical effortwould be required to produce those billing determinants. However, since billing determinants forthe refiled rates were required, they were produced for the Refiling, in Table Rates A-5.2. Thosebilling determinants formed the basis for the calculation of revenues under refiled rates.

TransAlta submitted that since revenue under existing rates was based on actual recorded 1998revenue, and since billing determinants under existing rates were not required or used, it wouldbe beyond the scope of this refiling to now create those determinants.

In response to IPCAA submissions, TransAlta submitted that for IPCAA to make its suggestion(p. 2) that the Transmission Service rate class is facing a 14% rather than a 10% increase,IPCAA must rewrite the actual 1998 billings and rates. If history were to be rewritten as IPCAAwould have it, then IPCAA members would not have been entitled in 1998 to the benefit of theRate Reduction Rider that year, a benefit its members have already accepted.

TransAlta noted IPCAA and IPPSA/SPPA challenges with respect to Option 21/G, use of 1998actual data, which contended that had forecast data been used, “…the DISCO would not havereceived the excess revenues of $15.5 million” and that, “The proper approach would be to useforecast revenues…..”. TransAlta submitted that those suggestions were without merit for thefollowing reasons:

• Selective use of forecast data is not appropriate. The Board directed that, for severalreasons, it would be appropriate for the Refiling to be based on 1998 actual loads, actualprices and actual revenues. To seek to single out one revenue item and advocate thatbecause the “actual” does not provide a result optimal for that item from the point of viewof rates sought by those intervenors is inappropriate.

• Further, while IPCAA and IPPSA/SPPA focus on the $15.5 million so-called “excessrevenue” that they suggest lies in the actual revenue figures, others may contend that in1998, the large industrial rate class received an “excess Rate Reduction Rider” of $29.7million through use of the 1998 actuals. On this point, see the AIPA.TAU-2, p. 2, wherethe Large General Service Time of Use ($7.527 million) and the Transmission Service($22.213 million), received as a rate class with a revenue to cost ratio then below 90%, atotal of $29.7 million refund benefits from the Rate Reduction Rider.



• Singling out an item like the GAC credit, and proposing a treatment such as IPCAA does,contravenes the ground-rules of the 1998 Negotiated Settlement, that the settlement is tobe taken as a whole and not selectively re-opened before the Board on a single issue.Moreover, IPCAA agreed to the parameters of that settlement.

TransAlta recommended that the Board resist IPCAA’s invitations to assume that customerswere on different rate, rider and option combinations during 1998 than they were, in fact,actually on. TransAlta illustrated this with examples of p. 6 – “if Option 21 customers had beenon standard rates,” and p. 8 – “if the Rate Refund Rider had not been in existence and paid tocustomers.”

Board Findings

In Decision U99035, the Board deemed the interim rates in place in 1996, 1997 and 1998 to befinal rates and the Board directed TransAlta to keep the overall increase in revenue arising fromthe rate redesign at less than 10% for any rate class. Therefore, the Board considers that the basefrom which the increase in revenues is measured should be the actual revenue from eachcustomer class in 1998. The Board notes that this was the base that TransAlta advised it used tocalculate each rate classes’ percentage increase.

The Board does not consider that 1996 rates and revenues, as suggested by some, would be anappropriate base to apply the 10% cap from and to address the issue of rate stability/rate shock.Nor does the Board accept that an appropriate base is either the level that customers were at on aforecast basis in 1998 or should have been at if circumstances were different.

Use of the 1998 revenue from each customer class as a base allows comparison of the annualizedincrease that each rate class is forecast to see due to the rate redesign relative to the amounts thecustomer class had been paying over a year in the recent past. The Board considers that thiscomparison would address the rate design principle of rate stability for customer classes.Therefore, that comparison will yield the percentage increase which the Board uses in itsexamination of submissions that customers may have experienced “rate shock” in the nextsection.

In Decision U99035, the Board recognized that, the previous rates were based on a structureappropriate for the 1992 test year under a very different regulatory regime. The Board furtherunderstood that the change in rates for some customers might be significant and even more thanthe 10% rate cap for each customer rate class. In the next section, the Board will considerwhether Decision U99035 should be reviewed and varied to moderate those rate increases, basedon the evidence and submissions before the Board.



(b) Should the Board Vary Decision U99035 with Respect to the10% Rate Increase Cap?

IPCAA made a number of submissions regarding the size of the rate increases (see previoussection, “What Base Should the 10% Cap be Applied To?”). ACD submitted that they did not contemplate the large increase in power costs imposed on themin a way that they would also be denied the ability to mitigate those costs by being priceresponsive. Specifically, ACD submitted that they were required to live with Old World Option12/F contracts and unable to choose between either Direct Connected Service - Rate 6410 andthe Direct Access Rate 6840 available to other large industrial customers. The ACD believed thatTransAlta would not allow them on Rate 6840.

ACD noted that in Decision U99035 the Board specifically directed that the DISCO keep theoverall increase in revenue arising from the rate redesign at less than 10% for any rate class. TheACD provided a graph indicating that for individual customers in the industrial rate class the rateincrease over a range of load factors could vary from about –15% to +25%. In its replysubmission, the ACD suggested that combining the increases with possible outcomes from theTA proceeding and worst case assumptions the rate increases may be as large as 35%. ACDsubmitted that the Board, in the past, was reluctant to create the degree of rate impact and indeedrate shock to customers that would flow from the refiling. ACD saw even less reason for suchrate shock results to be imposed at this time of transition to market-based rates. ACDrecommended several different approaches to cap the increase at 10% for individual customers,including treating Rate 6410 as a separate rate class or maintaining demand charges to narrowthe range of rate changes that large industrial customers are subject to. In reply, ACD submitted that given the uncertainty of the impact on individual customers bills, aprice cap would provide more effective shielding than the rate redesign. The price cap wouldalso be simpler to administer and would allow the cost of shielding to be tracked in a deferralaccount to be shared among all customers. ACD submitted that a 10% price cap for individualcustomers would be consistent with the objective and level of increase established by the Boardas reasonable.

ACD argued that history has shown that cost allocation methods are not absolute measures ofeither accuracy or fairness. Slavishly following new cost allocation methods will result in ratespikes. Utilization of the criterion of rate stability effectively smoothes rates, particularly whensignificant changes are made in cost allocation methods. The market will determine costs in2001, so temperance should be adopted to ensure that radical changes are not made to rates thatmay only be reversed as a liquid market develops. A rate spike in the transition provides nobeneficial results and likely will increase business uncertainty with attendant negativeconsequences. The ACD stated it had demonstrated the practical negative consequence for largeindustrial customers with a high dependence on electricity in their processes.



With respect to the Option 12/F contracts, TransAlta submitted that ACD were only required toadhere to the decision they made when they chose to remain on Option 12/F during the transitionto a competitive market for the supply of electricity in Alberta. As summarized on page 13 ofTransAlta’s Argument in Chief -- Direct Access Tariff, Option F, Option G, dated November 23,1998:

TransAlta also worked closely with IPCAA to develop three different optionsfrom which Option 12 customers could choose. These three options were outlinedin TransAlta’s filing to the Board dated June 21, 1996, entered in theseproceedings as Exhibit 24:

1. Continue to stay on embedded rates and receive a credit for beinginterruptible and continue to be interrupted as described below;

2. Terminate the agreement prior to December 31, 1996 and revert to non-interruptible rates; or

3. Move to Option 21 - Planned Interruption Transition Alternative.

TransAlta noted that the customers who chose to retain Option 12 had committed that their loadwould remain interruptible until August 31, 2000.

However, TransAlta recommended, provided the Option 12/F commitment is honored, that theBoard should accept ACD’s request to be eligible for Rate 6840. TransAlta had no objection toOption 12/F customers moving to either Rate 6840, (as approved for November 1999) or to Rate6400, when the Board approves that rate. An Option 12/F customer that takes Rate 6840 wouldthen have the opportunity to respond to pool price in a manner similar to an Option 21/Gcustomer. The difference being that an Option 12/F customer would be obligated to interruptload when requested, and receive the full Option 12/F credit, whereas an Option 21/G customeris under no obligation to interrupt load, but receives a reduced Option 12/F credit. TransAltaviewed its position to be complementary to ACD’s. TransAlta also noted that, when Option Fexpires on 31 August 2000, customers could choose rate 6400 or 6410 or Direct Access Rate6840 with no interruptibility. Any choice would of course be subject to other considerations,such as the requirement for a minimum term of six months and six month notice on Rate 6840. TransAlta noted that rate increases of 24% or 25% are only arrived at when one takes away acustomer’s Unused Investment Credit Option 10/B credit. The rate increase for a 50 MWcustomer with a very high load factor, when properly stated with no change to his Option 10/Bcredits is 19% from ACD, 17 or 17% shown in Information Response ADC.TAU-3. Thedifference appears to arise from the assumptions around energy use in the time-of-use (TOU)periods. TransAlta stated that the many references to this 24% or 25% increase are misleading,

17 p.24



firstly, because they are nowhere qualified by the assumed Option 10/B removal and secondly,because TransAlta is not proposing to take away any customer’s Option 10/B credit.

TransAlta noted that ACD submitted that, in the era prior to deregulation, the load patterncharacteristics of ACD customers were desirable and benefited the system and that suchcustomers might expect to benefit from the deregulation process more than others. Theirarguments then imply that such benefits should then be brought back to the present for 1999 and2000 rates. Whatever may turn out to be the post-2000 case, the rates for ACD customers in therefiling reflect the Decision of the Board as specifically applicable to the 1999/2000 period. Itshould be noted that the ACD customers might reasonably be described as benefiting from theBoard’s imposition of the 10% cap on rate class increases for 1999/2000.

Regarding ACD’s suggestion that a rate increase cap of 10% be used for each customer,TransAlta submitted that it would not be “a simple method” as ACD suggested. It would benecessary to establish the extent of the subsidy required for each customer and then the Boardwould have to approve which rate class(es) would provide such a subsidy. In any event, thesuggestion goes beyond the bounds of refiling issues. Regarding ACD’s alternative suggestion to continue use of Rate 790, TransAlta submitted thatthe use of Rate 790 is inconsistent with the required flow-through of TA charges on a dollar fordollar basis.

TransAlta also noted that ACD suggested that TransAlta be directed to “maintain demandcharges” for customers on the Rate 6400 series. TransAlta submitted that the question of whetherthe energy supply component of rates should be energy-based or demand-based was thoroughlyexplored in the Phase II proceedings.18 TransAlta submitted that the Board considered how ratesshould be structured in Decision U99035, and concluded the following:

Theoretically, rate stability, energy conservation, value of service, historicaldevelopment, and customer acceptance concerns should not prevent customers or futurecompetitors from beginning and continuing to receive the accurate cost information theyrequire to make market driven choices.19

TransAlta stated that ACD’s submission does not raise a refiling compliance issue.

The MI submitted that the 24% increase determined in Appendix A of the ACD submission wasthe worst possible case (100% load factor) and no evidence was submitted to substantiate thatany of the ACD members have load factors approaching 100%. TransCanada-TAU-2 indicatedthat the average load factor for Rate 6400 and 6410 was 83% and 87% respectively. The MI also

18 See, for example, the Evidence of Robert D. Knecht, Exhibit 50, p.16-1919 p.51



submitted that in effect ACD had under paid for the first three years of the five-year transition,due to the Old World allocation methodology, which benefited them.

The MI also noted that, in TransAlta’s original Phase II filing, TransAlta indicated that theproposed tariffs should replace the interim rates including the Electric Energy Marketing Agency(EEMA) Flow-through Rider (approved January 1, 1996 in Order E95123) and the interim(6.9%) Rate Reduction Rider (effective June 1, 1998 as approved by Order U98093). However,in Table Rates A-2.0 of the Phase II Application, the proposed changes in rates were shownrelative to the rates existing in January 1996. The MI submitted that the 10% maximum increasethe Board directed was relative to the January 1996 rates, otherwise the net cap would haveeffectively been 3.1%.

In contrast in the refiling TransAlta applied the 10% cap to the 1998 revenues. Therefore, acustomer or rate class receiving the maximum 10% rate increase, will only receive a net increaseof 3.1% over January 1996 rates since the 6.9% reduction rider was in effect in 1998.

The MI submitted that all submissions that object to increases in excess of 10% should beviewed in that light. The MI also noted that the Board made it clear in U99035 that someindividual customers could expect increases in excess of 10% if their usage characteristicswarranted.

The MI also noted another mitigating factor that the parties seeking R&V had ignored was thatthe Board deemed the interim rates in place from January 1, 1996 to December 31, 1998 to befinal rates. Those rates reflected Old World generation cost allocation and benefited thosecustomers complaining about rate shock for the first three years of the five-year transition toderegulation. The MI submitted that the benefit those customers received from 1996 to 1998should be considered.

The REA/AAMDC submitted that the rate changes being seen by large customers wouldnormally have occurred in increments over the four years 1996 to 1999 rather than beingdelayed. Therefore, the Board should view the changes in rate levels not only against currentrates with rate reduction riders but also relative to the rates in place in 1996 before therestructured industry came into play. The REA/AAMDC submitted that it has been clear sincethe date of the Phase II filing (June 30, 1998) that the large industrial customers should be seeinga rate increase rather than the rate reduction riders they actually saw. The Board Decision shouldhave at least been one of the potential outcomes those customers could have anticipated.

The REA/AAMDC also submitted that in Decision U99035 the Board was not trying to preventany individual customers from receiving an increase in excess of 10% (particularly whenmeasured with respect to rates with significant refund riders) under any and all circumstances.The REA/AAMDC submitted that any shielding of individual customers should remain withinthat customer’s rate class.



Board Findings

In the previous section, the Board determined that use of the revenues from each rate class, as abase, crystallizes the increase that the same rate class sees due to rate changes compared to theamounts the rate class had been paying during a year in the recent past.

The Board notes that there was disagreement and uncertainty as among parties as to what themaximum rate increase could be or would be for potential and current customers with high loadfactors. The Board notes that parties indicated maximum increases at the time of their refilingsubmissions. The maximum increase , arising solely out of the change in rates, appears to beapproximately 20% for any individual customer. However, the Board notes that the predictedmaximum increase for those high load factor customers will be moderated as a result of thechanges the Board has directed in this Decision and other Decisions.

The Board notes that the predicted maximum increase for those high load factor customers willbe significantly reduced as a result of the changes the Board has approved or directed in thisDecision. The first change is the reductions in the RP and energy supply costs as set out inAdjustments to the Cost of Service Study. The second change is the reduction in the level ofUnused Investment Credit Option 10/B credits paid by the Transmission Service and LargeGeneral Service rate classes set out in Section 6 – Unused Investment Credits Option 10 andOption B.

Further, the annualized effect of the increases will be also smaller since the new rates will not beimplemented on January 1, 2000. A March 1, 2000 implementation would reduce a 20% increaseto 16.7% for the whole of 2000 on an annualized basis.

Lastly, although the impact of a possible 1999/2000 Decision was not considered in the Phase IIproceeding, the Board notes that the increases will be further mitigated by the Board’s1999/2000 Decisions, which will reduce rates arising from this Decision. The 1999/2000Decisions directed that an across the board reduction rider be implemented, once the new ratesarising out of this Decision are implemented. This would reduce the maximum increase to lessthan 15% on an annualized basis.

The Board also notes that changes in other rates approved by the Board in 2000 may change theoverall annualized electricity related increases seen by customers, as may the impact of the poolprice deferral accounts arising out of the 1999/2000 Decisions. For all customers, the Boardnotes that the rates arising out of this Decision, as adjusted for the 1999/2000 Decisions, willlikely be in place for the remainder of the transition period during the year 2000. While thoseincreases or decreases are now relatively certain, changes arising as a result of changing powerpool prices and of incorporating the results of the assorted deferral accounts including those inthe 1999/2000 Decisions and any rate changes implemented to reflect the TA tariff refiling areuncertain. For large transmission connected customers, there will be further changes as a resultof the flow through of new rates arising from the TA rate refiling.



The uncertainties arising from the timing and interaction of rate changes and deferral accounts ofcertain participants may be make determination of annualized rate increases difficult to predict.Further, the Board considers that a determination of whether the level of rate increases wouldresult in “rate shock” is more complex than a simple examination of rate increases alone. The determination must consider all the costs and benefits available to customers from their useof electricity in the January 1 to December 31, 2000 period in the restructured industry. Therestructuring of rates ordered in Decision U99035 recognized the transition from customers whointeracted with a single integrated utility to customers who interact with the TA, the DISCO, andthe Power Pool. The Board considers any benefits and payments certain customers receive whicharise out of that customer’s connection to the system would serve to reduce any “shock”customers see from the increase in the rate component of their net costs of being connected toand receiving power in Alberta. In many cases, the Board expects that the annualized rateincreases seen by industrial customers will be, at least partially, offset by the benefits available tothem during the year 2000.

Most industrial customers now have the option of the DAT rate (Rate 6800) for some or theirentire load to allow them to reduce their costs from those under the refiled fixed rates on whichthe rate increase comparisons are made. The Board also agrees with TransAlta and the ACD thatallowing the Option 12/F customers to choose either Transmission Service DAT (Rate 6840) orTransmission Service (Rate 6400), while retaining the interruptibility requirements and credits ofOption 12/F, would be appropriate. Rate 6840 would allow them the same opportunity availableto other large industrial customers to mitigate their costs upon implementation of the rates arisingout of this Decision rather than waiting until after August 31, 2000. The Board also recognizes that after August 31, 2000, Option 12/F customers will likely receivehigher payments for being interruptible than those payments that they received under Option12/F in 1998. Several parties including the ACD20 have indicated that the value of the ability tointerrupt exceeds the contractual credits under Option 12/F. The ACD suggested that the creditsbe increased 10 times to reflect their value. For that reason, the Board envisions that theannualized increase to ACD members in 2000 calculated using the new rates will likely be, atleast partially, offset by the higher values these customers will obtain by selling theirinterruptibility and by using their access to the DAT rate.

Similarly, the Board notes that some other industrial customers have and will likely continue toreceive payments for being interruptible and for other system support services from theunregulated market for system support and interruptible loads.

Therefore, the Board considers that a determination of whether a “shock” in the overallannualized cost of electricity will be experienced, by a rate class and or by an individual

20 Decision U99035, p.142-143



customer, should consider not only the rate increase but also the payments, opportunities,benefits and factors outlined above. The Board recognizes that such a determination of the netincreases would be, at best problematic, due to the unregulated nature of some of the elements.Further, the changes in the TA tariffs and the uncertainty of the effect of the outcome of thedeferral accounts arising from the 1999/2000 Decisions would make such determination difficult,if not impossible, at this time.

The rate reduction riders of 1996, 1997 and 1998 were on an across-the-board basis rather thanreflecting any reallocation of costs as between customer classes that may have been moreappropriate. This introduces an additional concern related to fairness. The interruptibility andhigh load factor of some large industrial customers were desirable to the system in the era priorto the EU Act and led to rates with credits for interruptibility, demand based allocation ofgeneration costs, and low run out energy costs. Those Old World rates allowed high load factorcustomers to share those benefits to the system. However, the Board notes that Old World rates,with some of those benefits, remained in effect through to the end of 1999. The rates in placesince 1996 did not reflect what the Board determined to be the appropriate cost allocation inDecision U99035. Therefore, the Board considers that TransAlta’s high load factor customersmay have paid less in recent years than what have been determined to be their fair share of costsunder the methodology in Decision U99035.

To summarize, the Board has provided measures to mitigate the effect of rate increases on rateclasses and has limited the increase to 10% (which becomes about 8.5% on an annualized basiswith a March 1, 2000 implementation date). The increase will be further reduced after the effectof the 1999/2000 Decisions is recognized. The Board accepts that individual customers willunavoidably vary from this rate class average. However, the Board also notes that individualcustomers have a number of ways to mitigate the impact of these rate changes or reduce netelectricity costs.

Therefore, the Board considers that further measures beyond those reflected in Decision U99035are not warranted, at this time in the transition to post-2000 deregulation. Particularly since thosecustomers, who will see the largest increases, appear to have benefited the most from the delay inthe redesign of rates after 1996 and may also benefit from payments from the TA and the PowerPool for their interruptibility and system support services. The Board also considers that therefiled rates reflect the basic realities of DISCO costs in the transition to 2001 and that partiesshould see those realities.

Therefore, the Board is not convinced, at this time, that it should change its determinations inDecision U99035 of a maximum of a 10% increase in the rates seen by any customer class.Further, the Board has not been persuaded that a cap should apply to rate change for anyindividual customer. As previously noted, the 1999/2000 Decisions have already ordered that therevenues which will be recovered through the rates arising from this Decision are to be reducedon an across the board basis.



(c) How Should Rate 6300 Series and Rate 6400 Series Customers be Grouped?

In its original Phase II filing, TransAlta made no distinction between different forms ofconnection for customers. Some Large General Time-of-Use Service - Rate 6300 and Rate 6400customers were served at the distribution voltage (below 25 kV), while some were served attransmission voltage. The distinction was on the basis of load size, with Rate 6300 servingcustomers with a normal billing capacity of greater than or equal to 2000 kW and less than10,000 kW and Rate 6400 serving customers with a normal billing capacity of greater than orequal to 10,000 kW.

In Direction 2 of Decision U99035, TransAlta was directed to pass through the actual TAbillings to every customer, served at 25 kV or higher, who is the only customer at a point ofdelivery. In TransAlta’s refiled rates, such customers were termed customers with “DirectConnected Services.” In TransAlta’s refiled rates, customers with a normal billing capacity ofgreater than or equal to 2000 kW and less than 10,000 kW were to be served under DirectConnected - Rate 6310, a subset of Rate 6300. Customers with a normal billing capacity ofgreater than or equal to 10,000 kW were included Rate 6410, a subset of Rate 6400.

The ACD sought to have Rate 6410 customers considered as a rate class separate from otherRate 6400 series customers. The ACD submitted that this approach would provide some ratestability for Rate 6410 customers.

CTMPN and TransCanada supported the treatment of Rates 6400 and 6410 as separate rateclasses. CTMPN was opposed to any increase in rates for individual customers above that whichwould result if a demand based allocation of RP were used. TransCanada submitted that the basis for creation of a rate class is having relativelyhomogeneous load and cost characteristics. TransCanada submitted that there were significantdifferences in load factor between Rate 6410 (87%) and Rate 6400 (66%) customers.TransCanada submitted that given differences in load factor, the size of the rate groups andmaterial impact of the proposed rate increases, Rate 6400 and 6410 should be treated as separateclasses each subject to the 10% rate cap. TransCanada submitted that Rates 6400 and 6410required review in a hearing process, where parties could explore matters to at least ensure thecalculation were correct. The Board needs to be aware of the full effect the proposed rates willhave on all customers, including Rate 6400/6410 customers.

The MI noted that TransAlta indicated that those customers do not constitute a separate rate classand should be considered a subset of the Rate 6400 class that consisted of customers over 10MW who are directly connected to the transmission system. The MI agreed that the line must bedrawn somewhere lest the 10% cap be extended to include combinations of rates and options.



TransAlta submitted that this did not seem a Refiling issue, since TransAlta proposed rateclasses, and the Board approved them in the Phase II. In any event, TransAlta submitted thatRate 6410 can not be reasonably conceived as a rate class unto itself. Grouping Rates 6310 and6410 together as a rate class of customers served at transmission voltage and leaving Rate 6300and 6400 as a rate class served at distribution voltages would have some logic.

Board Findings

The Board notes that the increases in rates to transmission attached customers may arise fromboth generation and transmission costs (which are passed through from the TA).

TransCanada submitted that Direct Connected - Rate 6410 should be considered a separate classdue to its higher average load factor than Transmission Service - Rate 6400. In DecisionU99035, the Board clearly sets out that the load factor does not matter with respect to theincremental generation charges the DISCO pays for the energy to supply its customers.Therefore, the Board does not consider that it is appropriate to differentiate generation charges toa subset of a rate class purely on the basis of that subset’s load factor.

With respect to transmission, the load factor will play the role set out in the TA’s rates. The TAcharges the DISCO sees from the TA are appropriately passed through to the direct connectedtransmission customer served under either Direct Connected - Rate 6310 or 6410. The Board also does not consider it appropriate to define new rate classes simply to reduce theincreases to the rates of a certain group of customers; particularly when the level of theannualized increases is so uncertain, as discussed in the previous section. Further, the Board doesnot see any other reason to consider Rate 6410 as a separate class.

The Board has also considered TransAlta’s suggestion that 6310 and 6410 might be grouped as arate class served at transmission voltage, leaving 6300 and 6400 grouped as a rate class served atdistribution voltage. However, in Decision U99035 the Board found:

With respect to the recommendation that service from the transmission system notbe restricted to customers with loads of 10,000 kW or greater, the Board notesTransAlta’s comment that Rate 6400 reflected the economies of scale of largecustomers. The Board considers the argument of TransAlta is reasonable andaccepts the limit on the availability of Rate 6400 to customers with a 10,000 kWminimum.21

The Board does not have any evidence that would cause it to vary the above findings fromDecision U99035 at this time. Therefore, the Board considers that the recombination of

21 p.102



customers by voltage is outside the scope of the refiling and could only be addressed at somefuture proceeding.



5. IRRIGATION RATES – RATE 2600 TO RATE 2900

AIPA submitted that the use of actual 1998 pool prices presents an anomaly in respect ofirrigation rates, since the summer pool prices in 1998 were higher than the winter prices.TransAlta submitted that, given the revenue to cost ratio in respect of irrigation load, the cap of10% would determine the limit of rate increase in any event, regardless of actual pool prices in1998.

AIPA noted that there appeared to be an error in the TransAlta Irrigation TOU Rate 2700 for On-peak hours, which is shown as 5.91 cents per kWh as per Table BR.TAU-2(c), November 15,1999. TransAlta reviewed the figures, and noted that there was no error. The 5.91 cents per kWhwas originally derived and presented in Table Rates A-5.1 Refiling on October 4, 1999.Subsequently, in a detailed response to the Board on time of use rates, TransAlta recalculated theTOU rates and R/C ratios for all rate classes, and presented them in Information ResponseBR.TAU-2. The rate of 5.91 cents per kWh was confirmed in Table BR.TAU-2(c). Board Findings

The Board notes its calculations indicate that, even after the changes that the Board has directedTransAlta to make to its cost of service study in this Decision, the irrigation rate will recoverabout $3 million less than the cost to serve irrigation customers. Therefore, the Board agreeswith TransAlta that the 10% rate increase cap would limit the increase for the irrigation rate classeven if the 1998 summer prices were adjusted to reflect more normal energy prices.

The Board notes that TransAlta recalculated and confirmed that the TOU rates in BR.TAU-2(c).Therefore, the Board also accepts that there was no error in the on-peak irrigation rate.



6. UNUSED INVESTMENT CREDITS OPTION 10 AND OPTION B

This section deals with the treatment of Option 10 and Option B credits (Option 10/B credits).TransAlta’s Unused Investment Credit Option is currently Option B and was formerly Option 10.Option 10/B credits were earned by customers for whom the total cost of the customer-relatedsupply facilities (including prepaid operation and maintenance) was less than TransAlta’sinvestment levels at the time they contracted for service with TransAlta. In Decision U99035, theBoard directed TransAlta to flow through all of the TA’s contract terms to transmissionconnected customers.

The ACD submitted that customers who have made economic tradeoffs to increase their unusedinvestment credits should be entitled to receive those Option 10/B credits for the duration of theirservice life. The ACD noted that TransAlta held the same view.

CTMPN, IPCAA, and TransCanada also supported the position that customers who receiveunused investment credits should continue to receive them for the duration of their service life.

IPCAA submitted that Option 10/B credits should not be contained in the rate class, but rathershould be paid for by all customers through an uplift to the Transmission Facility Owner (TFO)tariff to the TA.

IPCAA noted that when a new industrial customer requires connection, TransAlta’s investmentpolicy determines the amount that it will invest to install facilities necessary to serve thecustomer. The actual facility cost can be less than, equal to, or greater than the maximuminvestment.

IPCAA noted that if the actual facility cost is greater than the maximum investment, thecustomer is required to make-up the difference through a contribution. In such a circumstance,TransAlta would add the full cost of the asset to rate base but there would be an offsettingamount recorded in customer contributions (which is treated as no cost capital). The net rate baseeffect is the addition of assets equal to the amount determined by the investment policy.

Further, IPCAA noted that if the actual facility cost is equal to the maximum amount dictated bythe investment policy, then the amount expended is the amount added to rate base. If the actualfacility cost is less than the amount dictated by the investment policy, only the actual facility costis added to rate base. but the customer will still pay rates based on the total transmission ratebase. (Transmission connected customers are now paying rates averaged from all the TFOs in theprovince). The Option B credit pays the customer a credit equivalent to a portion of theannualized carrying cost of the unused investment.

The overall effect of these arrangements, IPCAA noted, is that the sum of the return anddepreciation on the rate base plus the unused investment credit is roughly equivalent to what thereturn and depreciation would have been had the investment level been expended. The customer

6. UNUSED INVESTMENT CREDITS OPTION 10 ANDOPTION B



pays transmission charges based on average investment levels and the Option B credit results inthe customer seeing some benefit from the fact that the cost of facilities to the customer waslower than the level indicated by the investment policy.

IPCAA noted that TransAlta has indicated that the effect of Option B credits is held within theLarge General Time-of-Use Service Rate 6300 and Transmission Service Rate 6400 rate classes.The total Option B credits are deducted from Rate 6300/6400 transmission revenue prior tocalculating transmission rates that recover 100% of cost. The effect of this is to have customersthat were on the same tariff as the Option B customers and that were required to pay acontribution to cover required investment in excess of the amount dictated by the investmentpolicy (and that do not receive Option B credits) also pay higher rates to offset credits paid tothose for whom less investment was required. IPCAA submitted that this result fails to accordwith either fairness or commonsense.

IPCAA submitted that a better approach would be to include these costs in the TFO tariff to theTA. The TA is seeing a lower tariff from TransAlta (as a TFO) because of the lower investmentrequired to serve the Option B customers and the costs related to the Option B credits shouldfollow the lower investment.

IPCAA submitted that TransAlta might resist such an approach because the 1999/2000 Phase Iproceeding has concluded. However, TransAlta did not include “farm transmission” costs in itsTFO tariff and yet advised the Board (by way of a letter to the Board dated October 29) “ . . .TransAlta proposes to correct this omission in the 1999/2000 Phase I refiling.” The samemechanism could be applied here. In IPCAA’s submission, TransAlta should be directed toinclude the cost of Option B credits to the Transmission Administrator as part of its TFO tariff.Absent this treatment, the cost of the credits should be allocated across all transmission costs ofTransAlta DISCO. The latter approach has been incorporated in Table Rates A-3.0 RefilingIPCAA.

TransCanada submitted that TransAlta should indicate that Option B would flow through theinvestment policy of the TA for new and incremental Direct Connected loads and be reworded tothat effect.

TransAlta noted that TransCanada requested that the word “Closed” be removed from Option Band that it was removed in the October 25, 1999 revisions to the refiling. However, TransAltasubmitted that TransCanada’s other Option B wording recommendations were not appropriate.TransAlta submitted that the TA investment policy will not be incorporated into TransAlta’sOption B. Option B will continue to reflect TransAlta’s investment policy, and only those DirectConnect loads which earlier qualified for and obtained Option B will continue to receive OptionB credits from TransAlta. All Direct Connected customers will be subject to a flow-through ofthe TA’s investment policy, however that may evolve.




TransAlta agreed that Option 10/B credits should continue to be due to the party who earnedthem. With respect to IPCAA’s other propositions, TransAlta submitted that IPCAA’s approach maybe appropriate on a going forward basis, if customer contributions are applied to reduce the TFOtariff, for this application and with regard to the Option 10/B credits currently in place, this is notan appropriate mechanism. In order to set an appropriate mechanism for today’s Option 10/B credits, it is necessary toexamine the evolution of today’s credits. As part of its investment policy introducing Option10/B credits, TransAlta reduced the maximum amount of its investment in customers over 2 MWto an average amount, and ensured all customers effectively received this average amount.Customers who need a lower investment received Option 10/B credits, while customers whowould have received a higher investment are required to make a contribution. Over time, theintent is that the increase in contributions would offset the Option 10/B credits, and that theeffect is contained within the rate class.

For these reasons, TransAlta proposed in the June 1998 Phase II filing to contain the effects ofOption 10/B credits within the rate class. TransAlta considers this is the appropriate means ofpaying the credit. TransAlta submitted that this matter was not properly a refiling issue. TransAlta noted that IPCAA seeks to raise TransAlta’s correction of the earlier omission of farmtransmission costs as a precedent to alter Option B parameters. TransAlta submitted that theprecedent does not stand – since Option B was an issue in the Phase II proceeding and thereforeis outside the parameters of the Refiling process to re-open.

Board Findings

The Board agrees that Option 10 and Unused Investment Credits - Option B Credits (Option10/B credits) credits should continue to be due to the customers who earned the unusedinvestment credits, at least until 2001. The treatment of these credits for periods after year-end2000 is a matter for consideration in a future proceeding.

The Board considers that it is appropriate, in this refiling Decision, to address which rate classesshould be allocated the costs of the investment credits. The Board agrees with IPCAA that thecredit now appears to benefit customers outside the Large General Time-of-Use Service Rate6300 and Transmission Service Rate 6400 rate classes. However, the Board is not convinced thatit is practical for TransAlta to include the cost of Option B credits to the TransmissionAdministrator as part of its TFO tariff at this time. However, all customers appear to receive thebenefits of lower TA rates than those which would have been required to fund the higherinvestment in transmission facilities, the Board accepts that all customers should share the costof the Option 10/B credits for the year 2000. The Board considers that the fairest treatment in2000 that keeps TransAlta whole, would be to allocate the cost of the Option 10/B credits across




all transmission costs of TransAlta DISCO. Accordingly, the Board directs TransAlta in itssecond refiling, to allocate the cost of Option 10/B credits across all transmission costs so that allcustomer classes share the costs of those credits for the year 2000.



7. CHANGES TO PLANNED INTERRUPTION TRANSITION ALTERNATIVE - OPTION G

By letter to the Board dated October 25, 1999 (the Option G letter), TransAlta filed a revisedOption G schedule

IPCAA submitted that in the Option G letter TransAlta filed a revised Option G schedule inwhich they correctly stated that “. . . an agreement had been previously reached with the OptionG customers to maintain the Option G credit in its current form until the expiry of the credit atthe end of August 31, 2000.”22 However, TransAlta continued by saying “. . . TransAlta hasattached a revised Option G schedule which maintains the current structure of the Option Gcredit.”23

IPCAA submitted that the revised Option G as proposed does not maintain the form of theexisting GAC in Option 21. The existing GAC reflects the difference between the averagemonthly pool price and the implicit generation cost in Rate 790 through a demand charge.

IPCAA submitted that if TransAlta’s revised Option G credit were implemented, it would reflectthe difference between the average monthly Pool Price less the H-factor and the generationportion of Large General Time-of-Use Service Rate 6300 and Transmission Service Rate 6400.This provides a large portion of the reconciliation between the Pool Price and embeddedgeneration costs on an energy basis and is clearly different from the existing treatment.

IPCAA submitted that the Option G mechanism filed on October 25 was:

• Inconsistent with the agreement between TransAlta and the Option 21 customers.• Inconsistent with the Board approval of the Option 21 credit on a demand basis in

Decision U99035.• Not required on the basis of any other portion of Decision U99035.

IPCAA submitted that the Board should direct TransAlta to revise Option G in accordance withits agreement with its customers. Specifically, the Regulated Generation Credit should not besubtracted from the Power Pool of Alberta Hourly Price. The Generation Access Credit shouldbe calculated based on the difference between the Pool Price and the generation charges in theapplicable General Time-of-Use Service Rate 6200, Rate 6300 or Rate 6400. As the generationcharges already incorporate the H-factor it is not necessary to incorporate it a second time.

In response to IPCAA’s submission, TransAlta noted that when Option 12 customers elected totransition to Option 21, the Generation Access Charge was introduced to compensate for thedifference between load on pool price flow through and load on fixed price rates. TransAlta

22 p.223 p.2

7. CHANGES TO PLANNED INTERRUPTION TRANSITIONALTERNATIVE OPTION G



submitted that the GAC structure proposed in its Refiling revision of October 25, 1999 can bedepicted as follows:

Rate 6300 and 6400 Option G Generation charges – H factor Pool price rate – GAC – H factor

TransAlta considered this would be an appropriate structure for the GAC for Option Gcustomers, since the GAC would:

• Properly compensate for the differences in generation charges between fixed rates and thepool price rate, in the transition from bundled rates like Rate 790, to rates with unbundledgeneration charges like rates 6300 and 6400

• Maintain the parity between customers on Option 12/F and Option 21/G, bearing in mindthat Option 21/G customers were originally option 12/F customers, who opted for anearly transition to pool price. The customers on Option G will see their pool pricegeneration charges modified by the H factor in the same way as customers who remainon Rate 6400 + Option F will see their fixed rate generation charges modified by the Hfactor,

• Meet the Board’s requirement that all rates incorporate an H factor,• Not double count the H Factor, or as stated by IPCAA “incorporate it a second time,”• Maintain the form of the existing GAC in Option 21, in that the GAC compensates for

the differences in generation charges between the fixed and pool price rates. Thisreconciliation is independent of the H Factor, which is kept equal in both.

Board Findings

The Board does not agree with IPCAA that the GAC revision proposed by TransAlta isinconsistent with the Board approval of the Option 21 credit on a demand basis in DecisionU99035 and is not required on the basis of any other portion of Decision U99035. In DecisionU99035, the Board only indicated that:

With respect to the exact formula to be used to calculate the GAC effective 1January 1999, the Board notes that the formula submitted by TransAlta in theirfiling of 22 January 1999 achieves revenue neutrality with Rate 790 and has beensupported by Option G customers. Therefore, the Board approves the GACcalculation contained in TransAlta’s filing of 22 January 1999.24

The Board made no indication in Decision U99035 as to what form the GAC should take whenTransAlta’s refiled rates replace Rate 790.

24 p.153

7. CHANGES TO PLANNED INTERRUPTION TRANSITIONALTERNATIVE OPTION G



However, the Board notes that the GAC was introduced to compensate for the differencebetween a load on pool price flow through and a load on fixed price rates. The Board agrees withTransAlta that the revised GAC in TransAlta’s October 25, 1999 letter would maintain the formof the existing GAC in Option 21, in that the GAC compensates for the differences in generationcharges between the fixed and pool price rates. Under the revised GAC and the other refiledrates, the reconciliation is independent of the H Factor, since it is equal in both the fixed and poolprice rates. Therefore, the Board agrees with TransAlta that the revised GAC in TransAlta’sOctober 25, 1999 letter is the form that the final GAC arising out of this Decision should takeconsidering the form of Large General Time-of-Use Service Rate 6300 and Transmission ServiceRate 6400. Therefore, the revised GAC should be implemented on the same date as Rates 6300and 6400.



8. DIRECT ACCESS TARIFF – RATE 6800

In its Refiling October 4, 1999, TransAlta requested that the Board consider making the PoolPrice Adjustment Factor reciprocal. TransAlta further noted that:

While TransAlta agrees the adjustment mechanism protects DAT customers frompool prices higher than forecast, failing to apply the adjustment as a charge whenthe pool prices are lower than forecast creates an unfair windfall for the DATcustomer which is not available to firm rate customers.

TransAlta elaborated on the impact of a non-reciprocal credit on page 7 of the Rates Evidence inthe Refiling.

In Decision U99105, the Board approved on an interim refundable basis effective November 1,1999, the DAT proposed by TransAlta in the refiling which included a reciprocal adjustment.The Board considered “that the DAT proposed is likely closer than the Temporary DATapproved in Order U99077 to the DAT that will be approved after examination of the Phase IIrefiling.”

However, in Decision U9903525 the Board recognized that:

…if the “H” factor is used, with no adjustments, the risk of an extended period ofpool prices above forecast might be so large as to bias customers against theoption of taking the actual pool price DAT. The Board considers that the actualpool price DAT is the DAT that will lead to the greatest market efficiencies.Therefore, an adjustment to the H factor is required to protect actual pool priceDAT customers from any significant increases in the average levels of pool pricesover the 1998 prices used in the calculation of “H” (as set out in Section 3(b), theactual 1998 pool prices are to be used in the calculation of H).

If actual future pool prices tend to be higher than those forecast using the 1998actual pool price record, the adjustment should leave customers who choose theactual pool price DAT generally no worse off than customers who choose fixedprice rates or TOU DAT. If the actual total UOV received by the DISCO duringeach billing month is used to calculate the monthly refund or credit due eachactual pool price DAT customer, then the changes in the overall UOV wouldgenerally offset the changes in overall pool price level. Then, if pool prices movemarkedly higher, actual pool price DAT customers will not automatically beworse off than customers on fixed rates. DAT customers who do respond to thepool price will more likely be better off than customers on fixed rates. DATcustomers must be allowed to respond to the hourly variation in pool prices

25 p.120-121

8. DIRECT ACCESS TARIFF – RATE 6800 TransAlta 1996—Phase II Refiling


without being overcharged because of the difference between forecast and actualaverage pool price. Therefore, the Board considers that the appropriate monthlyadjustment per kWh billed in the month would be defined as:

Adjustment = billing month’s total actual DISCO UOV refund – 1998 month’s total DISCO UOV refund 1998 DISCO monthly energy use

The Board considers that the adjustment should only be passed on when it ispositive and benefits actual pool price DAT customers. Otherwise, when theadjustment is negative (i.e. pool prices are lower than forecast), a DAT customermight end up worse off than fixed rate customers even if the DAT customer werereducing load during high pool price periods. In the case of lower than forecastprices, the impact on the DISCO of providing the adjustment is minimal since theDISCO will likely have saved more than the amount of the adjustment throughlower than forecast purchase costs for other customers. Also the DISCO willpotentially benefit from the downward pressure on the cost of energy. In the caseof higher than forecast prices the DISCO would pay the extra at any rate if allcustomers remained on fixed rates.

Therefore, the Board directs TransAlta to design its actual pool price DAT ratewith the separated components which follow:

• the actual pool price in each hour less the adjustment amount if theadjustment is positive as the cost of energy component;

• the fixed amount “H” charge calculated using the 1998 pool price recordand 1998 total TransAlta DISCO annual energy usage; and

• TA Billings charges which pass through the TOU charges in the TA’srates.

IPCAA submitted that the Phase II proceedings failed to develop usable Direct Access Tariffsand that would likely mean that no meaningful price responsive load (outside of OptionG/Option 21) will be added to the system prior to January 1, 2001.

IPCAA submitted that the Board’s actual Pool Price DAT is unattractive to customers due to theamount of Pool Price exposure it introduces and is not usable by most customers as the amountof hedge received declines with curtailment. A mechanism that reduces the amount of hedgereceived as a result of curtailment only works for customers who can curtail and make upproduction in subsequent periods but most industrial customers do not have this ability.

The weakness in the mechanism, IPCAA submitted, is ultimately revealed by considering acustomer that curtails through a whole month when the pool price exceeds its embedded energycost. With the actual Pool Price DAT, the customer would receive no entitlement refund. This“loss of the hedge” is not merely an academic concern. For example, in October 1999 the Pool



Price exceeded $200/MWh for 5% of the hours. A customer on the actual pool price DAT thatcurtailed for all of these hours should receive the difference between the Pool Price and itsembedded cost of energy for the amount of load curtailed. The actual Pool Price DAT would firstreduce the refund by 10% as this is the proportion of the customer’s load that would be unhedgedand would further reduce the refund by 5% to reflect the amount of load that was curtailed. In theend, the customer would only receive 85% of the amount that a proper DAT would refund.

IPCAA noted that TransAlta argued, in its refiling, that the monthly adjustment for the DATshould be reciprocal. IPCAA submitted that, the non-reciprocal adjustment may, in a customer’sview be a small compensation for the degree of pool price and gas price exposure that mustnecessarily be taken on if a customer switches to the actual Pool Price DAT. In TransAlta’s case,the DISCO was unhedged for 10% of its fixed price load (based on called entitlements). On aforecast basis this percentage grows.

In its reply submission, IPCAA submitted that TransAlta should be directed to maintain the GACmechanism to the later of December 31, 2000 or the full implementation of customer choice. Inits original Phase II filing, TransAlta was comfortable with a Direct Access Tariff that hedged acustomer’s entire load, and the GAC could do it. Customers have experience in responding topool prices under the GAC and not the DAT. Customers should not have to develop newcompetencies to manage pool price risk under the DAT while preparing for full pool priceexposure and commercial hedging only four months later.

IPPSA/SPPA submitted that, if an artificial incentive for customers to switch to Rate 6800(DAT) is created by the Board’s ruling, it is appropriate given the current industry structure. Itwas also clear from the Decision that providing incentives for customers to move to TOU andpool price flow through rates was contemplated. IPSAA/SPPA also submitted that it wasinappropriate for TransAlta to implement a “variance” in its refiling without going through theR&V process.

TransAlta submitted that as discussed in BR.TAU-3, the reciprocal adjustment made was toimplement the Board’s direction to use 1998 actual data, in a manner that takes account of thesystemic distinction of DAT rates from other firm rates.

TransAlta submitted that IPCAA agrees in principle that this would be a windfall to the DATcustomer. IPCAA stated that the non-reciprocal adjustment may, in a customer’s view, be asmall compensation for the degree of power pool price and gas price exposure that must be takenon, if a customer switches to the actual pool price DAT. IPCAA does not address the larger issueof why any customer should receive a windfall. TransAlta submitted that the Board should takethe wider view, and ensure fairness to all customers by making the Pool Price Adjustment areciprocal item, which would be a charge when the pool price is low and a credit when the poolprice is high.



TransAlta submitted that Information Response BR.TAU-3 illustrated how a non-reciprocaladjustment creates an artificial and inappropriate incentive to switch to DAT and further, that theonly fair way to implement the Pool Price Adjustment factor in the DAT was to make itreciprocal.

Board Findings

The Board considers that IPCAA’s arguments regarding DAT design would only have weight ifit is assumed that all DAT load is entitled to own sufficient hedges to fully hedge its load evenwhile other customer load is not so entitled. While IPCAA is correct that not all TransAlta’s loadis hedged for an actual Pool Price DAT customer, fixed rate customers similarly do not receive areduction in the pool price on their entire load through the H-factor. On a forecast basis, allcustomers are impacted similarly, since TransAlta DISCO’s entitlements hedges are generallyinsufficient to cover the entire customer load it serves. Clearly, under the H-factor design inDecision U99035, other customers would be required to forfeit some of their rights to the hedgevalue to fully hedge DAT customers.

In regards to TransAlta’s request that the Board vary Decision U99035 to make the Pool PriceAdjustment Factor reciprocal, the Board notes that in Decision U99035 the Board clearlyunderstood that there would be some distortion of the pool price risk to the DISCO. However,the Board considered that if pool prices were less than forecast, the distortion would not effectthe DISCO in a negative way if its actual pool price DAT load were less than its fixed price load.In essence, the Board allowed DAT customers to share in the overall reduction in DISCO costswhich could arise from DAT customer response to pool price which was not reflected in theforecast pool price (the actual 1998 pool price record) on which the rates were based.

If pool prices were higher than the forecast (based on the 1998 actual pool price record), theBoard notes that TransAlta DISCO would be no worse off as a result of supplying theadjustment, than if TransAlta served all of the actual pool price DAT customers on the fixedTOU DAT rate.

The Board is not persuaded by either the TransAlta or the IPCAA arguments that the DATdesigned in Decision pply the Pool Price Adjustment only when it results in a credit to thecustomer in its final DAT, as of the effective date of this Decision.

In Decision U99105, the Board approved on an interim refundable basis effective November 1,1999. The DAT proposed by TransAlta in the refiling included a reciprocal adjustment. TheBoard considers that a customer’s choice to be on the interim DAT would have been based oncomparison to service under the other rate options available at the time the customer was on therate. Therefore, the Board will not direct TransAlta to retroactively adjust the interim DATbillings for each customer to reflect the Board’s Decision to not vary Direction 39 and the finallevel of the rates arising out of Decision U99035.



However, the Board directs TransAlta to adjust the interim DAT billings from the effective dateof this Decision onwards to reflect the Board’s Findings to not vary Direction 39 of DecisionU99035.

The Board notes that under the DAT design, in Decision U99035,26 customers are required, inmost circumstances, to be on the DAT for a total period of at least one year before they maymove to another rate. This results from two requirements for DAT customers. Firstly, a DATcustomer is required to take DAT service for 6 months before it may give notice that it elects tobe billed under a different tariff. Secondly, a DAT customer must also “give six months notice ofthe effective date of the change if it elects to be billed pursuant to another tariff.”27

The Board recognizes that current interim DAT customers did not know the terms of the finalDAT and other final rates when these customers signed for the interim DAT rate. Accordingly,the Board considers that it would be fair to current interim DAT customers to allow them a one-time optionto elect to switch to another rate within 60 days of the effective date of the final ratesarising from this Decision.

After the 60-day option period, any customer who has not elected to switch shall continue to beserved under the final DAT and shall be subject to the notice provisions of that rate. For formerinterim DAT customers, after the 60-day option period, the Board considers that thedetermination of whether the DAT customer has taken DAT service for six months should usethe date the customer commenced service under the interim or TDAT. 28

With respect to the implementation of the final DAT, the Board directs TransAlta to incorporatethe following provisions:

• To switch all interim DAT customers to service on the final DAT, commencing on thedate that the final DAT is effective.

• To provide, at that time, a one-time option, to all former interim DAT customers to electto switch to another rate within 60 days.

• This one-option is subject to other switching provisions in TransAlta’s Terms andConditions.

• This one-time option is available for a 60-day period, commencing on the date that thefinal DAT is effective.

• If a customer gives notice to switch to another rate, within this one-time 60-day period,the newly selected rate will be effective at the start of the next billing period.

• At the completion of this one-time 60 day option period, any former interim DATcustomer who has not elected to switch, shall continue to be served under the final DATand shall be subject to the notice provisions of that rate.

26 p.121-12227 EU Act, section 31.6 (8)(9)(10)28 Decision U99015



• For additional clarity, after this one-time 60 day period is over, a former interim DATcustomer served on the DAT is required to take DAT service for 6 months before thecustomer may give notice that it elects to be billed under a different tariff. The customermust also give six months notice of the effective date of the change if it elects to be billedpursuant to another tariff.

• For former interim DAT customers, the determination of whether the customer has takenDAT service for 6 months should use the date the customer commenced service under theinterim or TDAT.



9. CONTRACT UNBUNDLING

In Decision U99035, the Board responded to intervenors concerns that it is important that theunbundling of contracts be resolved as soon as possible with two Directions.

Direction 45 follows:

Therefore, TransAlta is directed to unbundle its investment policy and offerseparate contracts for all of its new or renewing customers for Energy Supply, TABillings, and DISCO Services each with an appropriate minimum term. TransAltashould provide examples of its unbundled contracts with its refiling concerningunbundling of contracts and Direction 46 concerning unbundling of investmentpolicy.

Direction 46 follows:

The Board therefore, directs TransAlta to review its investment policy andprovide at the PDT proceeding the results of its review including the necessaryevidence to support the determined investment levels including the breakdown ofthe portion of the investment which is for distribution system fixed costs andtransmission system costs.

In Decision U99105, the Board subsequently indicated that:

The Board agrees with intervenors that it is important that the unbundling ofcontracts be resolved as soon as possible, particularly since the Board notes thatthe filing date for the PDT proceeding has been pushed back from 29 October1999 to some as yet undetermined date.

However, the Board considers that that most, if not all, contract unbundling andinvestment level issues fall under the terms and conditions of electrical service.The Board considers that, if the T&C TransAlta proposes are approved on aninterim, refundable basis, any contract specifying terms and conditionssubstantially different than those eventually approved by the Board will be subjectto the Board approved terms and conditions, rather than those set out in thecontract.

Therefore, the Board approves the T&C as proposed in TransAlta’s refiling on aninterim, refundable basis effective 1 November 1999.

In its refiling submission, IPPCA again sought direction from the Board as to the timing of aresponse to Direction 45 of Decision U99035, regarding the unbundling of contracts.

9. CONTRACT UNBUNDLING TransAlta 1996—Phase II Refiling


IPSSA/SPPA also requested that TransAlta comply with directions 45 and 46 (unbundling ofinvestment policy).

TransAlta noted that in recent discussions with customers, TransAlta agreed to file, by year-end1999, pro forma contractual provisions to effect the unbundling. However, TransAlta submittedthat Direction 46 clearly deals with matters that are germane to, and should be dealt with as partof, the Distribution Access Tariff proceeding.

Board Findings

The Board notes that TransAlta made an application in regard to contract unbundling in late1999. The Board considers that the matter should be left to the process arising out of thatapplication.

With respect to the issue of unbundling of investment policy, the Board notes that the final TAtariff with its investment policy will likely be approved before the filing of the DistributionTariff application. The Board continues to be of the view that the upcoming Distribution Tariffproceeding is the appropriate forum in which to address the unbundling of DISCO investmentpolicy.



10. DESIGN OF TIME-OF-USE RATES

In Decision U99035, the Board directed TransAlta to design time-of-use (TOU) rates, whichallow each TOU customer, regardless of customer class, to see the same pool price signal in eachTOU period. In Direction 12, the Board directed TransAlta to use the average actual pool price ineach TOU period in 1998, as the cost of energy component in the TOU rates.

In the refiling, TransAlta indicated that approach was problematic since each class has anindividual customer load profile which, when applied to the 1998 pool price record, result in adifferent average cost of energy for each class. TransAlta submitted that TOU rates should bedesigned using average pool costs for each TOU interval, rather than the pool price, to keep eachcustomer class revenue-neutral if the entire rate class uses the TOU rate. TransAlta alsosubmitted that it was not possible to set the Revenue/Cost ratio for energy costs to 100% perDirection 7 of Decision U99035.

IPCAA agreed with TransAlta that it would be inappropriate for customer classes to see the sameTOU rates for two reasons.

First, as TransAlta pointed out in its response to BR.TAU-2, each rate class exhibits its owndemand patterns and therefore each rate class would have a different weighted average poolpurchase cost for any period greater than one hour in length. The different demand patterns fordifferent customer classes requires the use of hourly metering or load profiling in a competitiveenvironment.

Second, since TOU rates are paid on the basis of energy at the customer meter, even customerswith similar load consumption profiles at the customer meter, allocated different distribution lossfactors, will not exhibit identical load profiles at the point of delivery (POD). This second pointcould be dealt with by recovering the cost of losses in the distribution charges rather than in theenergy charges. While an approach of including losses in the distribution charges was outlined inthe Distribution Regulation, and adopted by parties in their initial Preliminary Distribution Tariffapplications, it was not used by either TransAlta or AE in their Phase II applications.

IPCAA submitted that for those two reasons TransAlta’s approach of calculating TOU chargeson the basis of the rate class weighted average pool purchase cost over the relevant period shouldbe adopted.

IPPSA/SPPA agreed with TransAlta that the TOU rates in the refiling would appear to violateDirection 12 (100% revenue to cost ratios for energy supply). There would appear to be atransfer of cost to very large industrial customers without significant benefit, since lowering theTOU generation costs for typically inelastic FIRM customers would not appear to encouragecustomers to move load to off-peak. If the Board can identify a method to resolve the issuesidentified by TransAlta in BR.TAU-2 and provide average TOU rates for all rate classes, whilemaintaining 100% energy supply revenue to cost ratios, then IPPSA/SPPA would be supportive.

10. DESIGN OF TIME-OF-USE RATES TransAlta 1996—Phase II Refiling


Board Findings

While the Board would prefer that the energy charge in the TOU rate be the same for every class,the Board recognizes that this would only occur if many of the time of use periods were reducedto only an hour in length as TransAlta indicated. In the worst case, the Board also recognizes thatthere might have to be a weekday, weekend and seasonal or monthly variation in the 24 periods.The Board considers that such a rate would be complex to design, to bill, and to administer,particularly since many current TOU customers’ interval meters are unable to provide 24-hourreadings. In the Board’s view a change of this complexity is beyond the scope of the refiling.Therefore, the Board accepts TransAlta’s TOU rate design, with the levels as adjusted to beconsistent with the Findings in this Decision.



11. OILFIELD RATES – RATE 4400, RATE 4500, RATE 4600 AND RATE 6100

(a) Rate 4500 - Oil and Gas (Energy) Service

IPPSA/SPPA submitted that there appeared to be something wrong with TransAlta’s rate 4500energy billing determinants. IPPSA/SPPA believed there was an error made by TransAlta in theBlock 1 Energy value and that it should have been 2,901 MWh per month and not 2.901 MWhper year.

To support their position, IPPSA/SPPA stated that the average load factor of 4.6%, based onTransAlta’s submission, was obviously too low since the customers would be better off underRate 290 if their load factor were less than 20%. IPPSA/SPPA submitted that the 2,901 MWh permonth corresponded to an average load factor of 54.7% would be more reasonable as it wascomparable to the average load factor of 44.0% for Oil and Gas (Capacity) Service Rate 4400.

IPPSA/SPPA submitted that the error would have a significant impact on the expected ratereduction for the pumping class, since TransAlta has underestimated the revenue it will collectfrom the pumping class.

In reply, TransAlta submitted that there was no error in the 2,901 MWh per year energy value forRate 4500 and that the 4.6% average load factor was of the order of magnitude expected forservices billing on Rate 4500. To support its position, TransAlta pointed to IPPSA/SPPA.TAU-4which stated that, “In designing the Oil & Gas (Energy) Service Rate 4500, TransAlta evaluatedthe load and load factor characteristics of customers who would benefit from lower bills underRate 4500, relative to Rate 4400.” Services which would benefit by being served onpredominantly energy based Rate 4500 relative to a predominantly demand based Rate 4400 arelow load factor services. TransAlta further submitted that the correct Rate 4400 energyconsumption is 699,499 MWh.

TransAlta submitted that these energy consumption numbers result in the appropriate revenueunder existing rates of $51.833 million, the appropriate revenue under refiled rates of $49.483million, and the % rate change numbers being correct as refiled.

(b) Rate 6100 (General Service)

IPPSA/SPPA provided two analyses which, in its submission, showed that the 6.2% ratereduction proposed by TransAlta for Rate 6100 did not make sense, particularly with respect tothe level seen by oilfield customers. Summaries of the two analyses follow.

First, IPPSA/SPPA noted certain items from a study of members who represented about 19% ofthe total revenue proposed to be collected from Rate 6100 and had an average load factor of73%. Those customers were to see an average increase of 0.5% moving from the current rate 790to the refiled rate 6100 compared to the average class reduction of 6.2%. IPPSA/SPPA also

11. OILFIELD RATES – RATE 4400, RATE 4500 ANDRATE 4600



noted that its calculations showed that a commercial customer with an average load factor wouldsee rate reductions in the order of 10% to 17%. Second, IPPSA/SPPA noted that using the forecast billing determinants of the original Phase IIfiling yields an average decrease to Rate 6100 of 4.4%. IPPSA/SPPA submitted that the make-upof the rate class could not have changed so significantly from the 1996 forecast to the 1998actuals to justify the difference between 6.2% and 4.4%. IPPSA/SPPA also presented a graph29 showing a separation of the 6100 class load into high loadfactor industrial customers and low load factor retail customers. Table 5 showed that generallylow load factor customers would see a substantial decrease while higher load factor customerswould see a small increase. IPPSA/SPPA submitted that while the Board thought it likely that oilfield customers would see agreater than average decrease, SPPA members will purchase electric energy from TransAlta inthe amount of $95 million representing an increase of 1.5% based on the refiled rates. Oilfieldcustomers consume more energy off-peak and yet are seeing very little benefit through the costallocation method. IPPSA/SPPA submitted that the Board should keep this in mind whenreviewing any submissions to increase the allocation of costs to oilfield and industrial customers.Further, IPPSA/SPPA requested that the Board revise its generation costs allocation Directionsto ensure that more appropriate prices are afforded to oilfield and industrial customers.

In response to IPPSA/SPPA, TransAlta submitted that it had designed Rate 6100, based on the1998 loads, to recover 100% of each of the costs of generation, transmission and distribution forthe rate class.30 Further, TransAlta showed that this represents a 6.2% reduction in the actualrevenue collected from these customers in 1998.31

TransAlta noted that it was unable to confirm the validity of any of the sources.32 TransAlta alsonoted that no detail was given as to the representative demand (kW) or energy of theIPPSA/SPPA study customers, either in aggregate or on average. TransAlta submitted that (i) asmall increase for the high load factor customers, (ii) the lower load factor of retail customersand (iii) the larger decrease for lower load factor customers, taken together, do not cast doubt onthe validity of TransAlta’s rate decrease for Rate 6100 of 6.2%.

Further TransAlta noted that IPPSA/SPPA referred to its Table 6, and calculated a 4.4% decreasefor Rate 6100, whereas TransAlta is showing a 6.2% decrease. TransAlta pointed out thefollowing regarding IPPSA/SPPA’s Table 6:

29 p.1530 Table Rates A-2.0 Refiling31 Table Rates A-1.0 Refiling32 IPPSA/SPPA’s Customer Study, Graph or Table 5




• it was based on billing determinants derived from a 1996 load forecast,• it did not reflect the change to actual 1998 billing determinants, and• it did not reflect the load moved to Rate 6100 from Rates 290 and 730 customers over

75 kW as described in IPCAA.TAU-13. TransAlta submitted that the two IPPSA/SPPA analyses, the first based on small sample ofcustomers and the second based on incomplete billing determinants, did not validly raisequestions as to TransAlta’s calculations. In response to IPPSA/SPPA requests for billing determinants under existing rates, TransAltanoted that revenue under existing rates was derived from actual recorded 1998 revenues by rateclass, and was not calculated from 1998 billing determinants. TransAlta submitted that billingdeterminants for existing rates were not required and were not produced for the October 4, 1999Refiling. TransAlta indicated that considerable analytical effort would be required to producethose billing determinants.33 However, since billing determinants for the refiled rates wererequired, they were produced for the Refiling,34 and formed the basis for the calculation ofrevenues under refiled rates.

In summary, TransAlta considered that since revenue under existing rates were based on actualrecorded 1998 revenue, and since billing determinants under existing rates were not required orused, it would be beyond the scope of this refiling to now create those determinants.

Board Findings

The Board is not convinced that there is the error that IPPSA/SPPA suggests in the actual Oiland Gas (Energy) Service Rate 4500 energy consumption. The load factor IPPSA/SPPAcalculates of 54.7% for Oil and Gas (Capacity) Service Rate 4500 is higher than that of Rate4400. The Board agrees with TransAlta that services which would benefit from being served on apredominantly energy based Rate 4500, relative to predominantly demand based Rate 4400, arelow load factor services.

The Board notes that the production of the 1998 billing determinants IPPSA/SPPA requestswould not result in a change to the Board’s findings in the Level of Rate Increases section. Inthat section the Board determined that the appropriate base from which to measure rate increasesis the 1998 actual revenues from each class, which must be determined using the actual 1998loads rather than 1998 billing determinants.

The Board considers that the approach directed in Decision U99035 properly weights on-peakand off-peak pool price, since the hourly pool price is applied to the hourly energy consumed by

33 IPCAA.TAU-1234 Table Rates A-5.2




each rate class. Under this approach, oilfield customers are appropriately charged the cost of theenergy, which matches the time period in which these customers are likely to consume energy.



12. OTHER MATTERS CONCERNING OILFIELD CUSTOMERS

IPPSA/SPPA noted that currently low load factor oilfield accounts are served under SmallGeneral Service Rate 290. IPPSA/SPPA submitted that the Board concluded, in DecisionU99035 that there was insufficient evidence to move the accounts to an oilfield rate. The Boarddirected further study and directed TransAlta to make Small General Service Rate 4100 (whichreplaces rate 290) available to oilfield customers currently on Rate 290.

The latter direction was made so that customers are able to choose service under Rate 4100, Oiland Gas (Capacity) Service Rate 4400, or Oil and Gas (Energy) Service Rate 4500. IPPSA/SPPAsubmitted that customers should also be able to choose Rate 4100 or Small General Time-of-UseService Rate 4200 for new services otherwise similar customers would be treated in adiscriminatory fashion, contrary to law. IPPSA/SPPA noted that instead TransAlta went a stepfurther and closed rate 4100 to new oilfield accounts or to accounts that wish to move to rate4100 from rates 4400, 4500 or Oil and Gas Time-of-Use Service Rate 4600 in the future.35

IPPSA/SPPA submitted that for economic operation, any oilfield account should be able to moveto rate 4100 or 4200 since the characteristics of oilfield accounts can change over time asoperations and reservoir conditions dictate as the IPPSA/SPPA Phase II evidence indicated.

IPPSA/SPPA noted that groups of small oilfield accounts elected to take Option 12 because theycould collectively be interrupted and could benefit the system at times of generation shortage.These groups then elected to move to Option 21/G, and in the absence of hourly metering werecharged the average monthly pool price. IPPSA/SPPA submitted that it would be unfair on theexpiry of the Planned Interruption Transition Alternative Option G, to force these accounts toupgrade their metering at about $2,000 per account. The Board should direct TransAlta to allowthese customers back on standard rates until the end of 2000 when retail competition arrives.

TransAlta agreed with the IPPSA/SPPA position that putting these customers on pool price flowthrough rates, as stipulated in Option 21/G, would impose an inordinate metering expense forboth the customer and the DISCO. Therefore, TransAlta supported IPPSA’s recommendationthat the only reasonable solution is to allow these customers back onto fixed price rates for thelast four months of year 2000.

TransAlta submitted that IPPSA/SPPA’s interpretation of the Board Directions was differentfrom TransAlta’s. TransAlta understood the Direction No 28 “…oilfield customers currently onRate 290…” meant that only existing oilfield services currently taking service under rate 290would be eligible to choose Rate 4100. By extension other oilfield services (e.g. existing servicesnot currently taking service on rate 290, or new services that materialize in the future) would notbe eligible to choose service under rate 4100.

35 IPPSA/SPPA.TAU-8

12. OTHER MATTERS CONCERNING OILFIELD CUSTOMERS TransAlta 1996—Phase II Refiling


TransAlta submitted that its interpretation of Direction 28 was supported by Direction 30, thatTransAlta design an additional rate for Oil & Gas Service, a metered rate that is predominantlyan energy based rate. TransAlta envisioned this rate being available to all oil & gas services,including existing services, whatever rate they are currently taking service on, and all newservices.

Board Findings

The Board notes that IPPSA/SPPA interpreted that Decision U99035 would allow new oilfieldcustomers to be eligible for service under the Small General Service Rate 4100. However, inDecision U99035, under Oil and Gas (Energy) Service Rate 4500, the Board found:

… no compelling reason to require small oilfield customers currently using Rate290 or Rate 730 to move to proposed Rate 4400 or 4500 without allowing themthe choice of remaining in the proposed Small General Service, Rate 4100. … IfTransAlta maintains that the costs to serve oilfield customers is different than thatfor Rate 4100 customers, TransAlta should prepare a study demonstrating this atthe time of its next general tariff application.

Under Rate 4500, Appropriate Allocation of Oilfield Costs, the Board accepted:

… that additional facilities were required to serve oilfield customers and thatthese customers should therefore bear the costs at this time, the Board considersthat these claims should be substantiated by further study. The Board considersthat such a study would determine whether or not the cost of oilfield facilitiesshould be allocated to other customer groups because of benefits they receive.

Further, under Rate 4500, Required Metering:

The Board therefore finds that customers should be given the choice as to whetheror not to install or upgrade meters, rather than being forced to install/upgrademeters now. Also, in line with this finding, the Board is of the view that newoilfield customers should have the choice of taking service under either Rate 4400or Rate 4500. The Board notes that Rate 4400 is a demand based rate andconsiders that some oilfield customers may prefer a rate with an energy meter.The only energy-based rate available under TransAlta’s proposal is Rate 4500,which includes a TOU meter that may be too costly, particularly for smallercustomers. The Board therefore directs TransAlta to design an additional rate forOil and Gas Service, a metered rate similar to Rate 4500 but without the TOUcomponent. Providing this choice will be consistent with other rates proposed byTransAlta, such as residential rates, where new customers can choose either thestandard or the TOU service metered service.

12. OTHER MATTERS CONCERNING OILFIELD CUSTOMERS TransAlta 1996—Phase II Refiling


The Board also notes that the refiled Rate 4500 is the energy rate that the Board directedTransAlta to design and that the Oil and Gas Time-of-Use Service Rate 4600 is the TOU rate.

Therefore, the Board considers that TransAlta’s interpretation is correct and that the Board’sintention was to only allow existing Rate 290 customers to be grandfathered in Rate 4100, atleast until a study was done. New customers would be eligible for Oil and Gas (Capacity)Service Rate 4400 – 4600, which reflects the higher costs of additional facilities to service newoilfield customers. The future studies would ascertain only whether grandfathered oilfieldcustomers should continue to be served under Rate 4100 and whether any of the higher costs toserve oilfield customers should be allocated to other customer groups because of the benefitsthey receive from oilfield related facilities. Therefore, the Board does not agree withIPSAA/SPPA’s interpretation.

The second issue raised was whether Option 21/G customers must be served on pool price flowthrough rates after the August 31, 2000 expiry of their contracts. The Board agrees that such anapproach would impose an inordinate metering expense for both the customer and the DISCO.Therefore, the Board accepts the TransAlta and IPPSA’s recommendation that the onlyreasonable solution is to allow these customers back onto fixed price rates for the last fourmonths of year 2000.



13. INTEREST ON INTEREST REFUND RIDER

In Decision U99035, the Board made the following findings in regard to interest on TransAlta’sover-collections in 1996 and 1997:

The Board finds that the circumstances in this case warrant the payment ofinterest on refunded amounts. Having decided to award interest, the Board notesthat there is no clear cut manner to determine the level or the manner in which theinterest should be calculated. The Board will use some simplifying assumptions inthis case to recognize that parties were not aware when the Phase I applicationwas filed that interest would be awarded and that TransAlta began refunding theover-collections in a short time frame after receipt of the Phase I Decision (PhaseI Decision U97065 issued 31 October 1997 and refunds began 1 January 1998).

As noted in Board Order U97156, TransAlta’s revenue surplus was $55.56million in 1996 and $56.35 million in 1997 as a result of the 1996 Phase IDecision. These amounts were refunded over the period 1 January 1998 until 31December 1998. In the interests of providing a calculation of interest that is notoverly complex, interest on the $55.56 million refund relating to the revenuesurplus in 1996 will be calculated from 1 July 1996 to 30 June 1998. Interest onthe $56.35 million refund relating to the over-collection in 1997 will be calculatedfrom 1 July 1997 to 30 June 1998. The rate of interest to be used will be the Bankof Canada’s Bank Rate plus 1½%. The yearly average Bank of Canada Rate for1996 is to be used to calculate the 1996 portion of interest (1 July 1996 to 31December 1996), the yearly average Bank of Canada rate for 1997 is to be usedfor 1997 and the yearly average Bank of Canada rate for 1998 is to be used tocalculate the 1998 portion of interest (1 January 1998 to 30 June 1998). Theinterest calculation will use a simple yearly rate and not a compounded interestrate. The interest will be refunded to customers on an across-the-board basis asthe refunds were paid in 1998 excluding any market based rates. These interestpayments shall be considered as a shareholder expense and can not be recoveredfrom customers.

The Board directs TransAlta to provide, in its refiling, a calculation of its interestrefund and a proposed rider to refund the interest to customers.

In Decision U99105, the Board approved TransAlta’s proposed Interest Refund Rider on aninterim refundable basis effective November 1, 1999. The CCA submitted that TransAlta had the use of the $9.61 million interest amount on overcollections for the period from July 1, 1998 to the date that TransAlta finishes refunding the overcollections. The CCA submitted that TransAlta should increase the $9.61 million to account forthe additional time that TransAlta effectively had the use of the $9.61 million (from July 1, 1998

13. INTEREST ON INTEREST REFUND RIDER TransAlta 1996—Phase II Refiling


to April 30, 2000). The CCA also submitted that the base used for the refund rider should notinclude the EEMA Rate Rider and the Rate Reduction Rider. The CCA’s argument was supported by the CTMPN. The MI submitted that there should be a one-time billing adjustment in respect of the refund of$9.61 million interest. While TransAlta desired a 12-month refund to be consistent with pastpractice and to be equitable to customers with seasonal or intermittent loads, the MI suggestedthe use of annual calendar revenues. The MI submitted that, if TransAlta refused to make atimely one-time refund, then TransAlta should be directed to add interest for use of the $9.61million for 2 years from mid-1998 to mid-2000.

The REA/AAMDC supported the MI’s position. AIPA expressed its concern as to how aone-time refund would reflect seasonal usage.

TransAlta submitted that the MI implied that the matter of a one-time billing adjustment inrespect of the refund of interest is a simple matter. However, TransAlta stated that the billingsystem is not set up to provide the customer by customer historical billing information in amanner that would allow a reasonable application of historical parameters for a one time refundto all customers. TransAlta stated that, to gather and apply such data on a customer by customerbasis would entail a massive exercise, which is a reason why refunds have not been so effected inthe past. To suggest that continuation of past practice, of refunds over a period sufficient toprovide fairness to various types of customers, is now a practice for which financial penalty mustbe exacted is unreasonable. TransAlta also stated that the MI approach was contrary to whatmust have been the implicit expectations of the Board in ordering interest in the manner it did. TransAlta submitted that the CCA recommended that interest be compounded on refundamounts, contrary to the Board’s decision. Historically refunds or surcharges have been madeover time to provide equity to customers with different seasonal load patterns. TransAlta alsosubmitted that the matter raised was not a Refiling issue, since Decision U99035 set out theinterest to be calculated and since the Decision did not contemplate interest on interest.TransAlta stated that the Board accepted that the seasonal variation of some customer usagemakes the refund period of 11 months proposed by TransAlta equitable for all customers.

In respect to the appropriate base to use, TransAlta submitted that the refund calculated reflectsthe level of base rates, and the EEMA Reduction Rider and the Rate Reduction Rider formedpart of the amounts embedded in February 1, 2000 rate levels. Those same components havebeen included in the rates declared final by the Board through to the end of 1998 in DecisionU99035.

13. INTEREST ON INTEREST REFUND RIDER TransAlta 1996—Phase II Refiling


Board Findings

In Decision U99105, the Board approved TransAlta’s proposed Interest Refund Rider on aninterim refundable basis effective November 1, 1999. The interim approval was made withoutprejudice to MI’s submission regarding the appropriateness of a one-time refund. However, thesubmissions made during the refiling process have not convinced the Board that there is reasonto move away from the past practice of dealing with refunds over a period sufficient to providefairness to various types of customers. The Board also accepts the methodology and base used byTransAlta to calculate the Interest Refund Rider.

Some intervenors have now questioned whether interest should be applied on the amount of theInterest Refund Rider. The Board has determined that it will award interest when the level ofinterest being considered is deemed to be material. Although, in Decision U99035, the Board didnot contemplate an award of interest on the interest amount, the Board considers that TransAltahas had use of the amount to be refunded through the Interest Refund Rider for a material periodof time. TransAlta held the $9.61 million of interest from July 1, 1998 to November 1, 1999. TheBoard further considers that the level of interest that would be paid on the $9.61 million is amaterial sum. Therefore, the Board finds that TransAlta should pay interest on the $9.61 millionthat represents the Interest Refund Rider.

The Board directs that TransAlta calculate interest on the $9.61 million over the period July 1,1998 to November 1, 1999. This represents the period of time immediately after the InterestRefund was calculated to apply to, until the time that the Interest Refund Rider was deemed to bein effect. The Board directs TransAlta to calculate the interest using the Bank of Canada rate plus1½%. The yearly average Bank of Canada rate for 1998 is to be used to calculate the 1998portion of interest (July 1, 1998 to December 31, 1998). The yearly average Bank of Canada ratefor 1999 is to be used to calculate the 1999 portion of interest (January 1, 1999 to October 31,1999). The interest calculation will use a simple yearly rate and not a compounded interest rate.TransAlta is directed to adjust the current Interest Refund Rider of (0.86)% and to continue toapply the Rider until October 31, 2000. The cost of this interest award is to be considered ashareholder expense.



14. SMALL GENERAL SERVICE - RATE 4100

The MI was concerned that the refiled Small General Service Rate 4100 was discriminatorysince TransAlta proposed to recover 140% of distribution costs and 116% of total costs allocatedto Rate 4100 customers while no other rate class recovers over 100% of distribution or totalcosts. The MI suggested that the Board should allow TransAlta some latitude to increase otherclasses above the 100% level and to avoid singling out Rate 4100 class for discriminatorytreatment.

PICA was also concerned that the 116% revenue-to-cost ratio (R/C) proposed for Rate 4100unduly discriminates against Rate 4100 customers since all other classes having R/C ratiosgreater than 100% were brought down to the 100% level. PICA noted that Rate 4100’s R/C ratiowas 140% and submitted that a more fair and equitable result could be achieved by keeping theR/C ratios of other rates slightly above 100%. MI36 similarly comments that:

With some small degree of latitude in the 100% revenue cost recovery ratios bycost source and rate class, TransAlta could avoid singling out one rate class forwhat is obviously discriminatory treatment.

The CCA noted that under the refiled Rate 4100, these customers would already receive a 7.1%reduction and in Decision U99035 the Board indicated that “decreases for small general serviceclass may have to be moderated to avoid significant adjustments to other rate classes.” The CCAsubmitted that stability of rates needed to be considered in conjunction with the revenue to costratio for proper rate design. CCA viewed that TransAlta had properly followed Board Directionsin this matter. There is no need to effect further rate reductions to Rate 4100 at the expense ofother rate classes. Acceptance of the MI proposal would severely impact residential customerssince they cannot use utility costs as a tax write off or flow utility costs to the “end user” likeother customers.

In response to the MI and PICA, TransAlta noted that in Decision U99035, the Board determineda course of moving all rates to a 100% R/C ratio for generation and transmission, and fordistribution where possible, subject to the 10% cap on rate increases. In MI.TAU-4, TransAltadescribed its conclusion to recover the shortfalls from Rate 4100 as follows:

…the latter solution was considered more appropriate since the small general service rateclass, while experiencing an over-recovery of 16% in its revenue-to-cost ratio, is stillenjoying a larger rate reduction than residential, oil & gas, general service or largegeneral service.

TransAlta described, in MI-TAU-4, the other alternatives it considered in meeting the shortfall inrevenue from the four rate classes whose revenue to cost ratios are below 100%.

36 p.5

14. SMALL GENERAL SERVICE - RATE 4100 TransAlta 1996—Phase II Refiling


Board Findings

In Decision U99035, page 85, the Board directed TransAlta to design rates so that the followingobjectives were achieved:

• The DISCO’s total charges related to Energy Supply, TA Billings and DISCOServices are unbundled, with the revenue to cost ratio set at 100%.

• The revenue to cost ratios for Energy Supply and TA Billings are each set at100% for every rate class; and to the extent possible the revenue to cost ratiosfor Energy Supply and TA Billings are set at 100% for individual customers.

• The overall increase in revenue over that collected from existing rates is keptat less than 10% for every class, by adjusting as required the “residual “DISCO services amounts to be recovered from customer classes.

In that Decision, the Board also recognized that the decrease to the rates for Small GeneralService rate class (Rate 4100) may have to be moderated to avoid significant adjustments toother rate classes.

In the refiling, TransAlta designed Rate 4100 so that the revenue to cost ratios were set at 100%each for Energy Supply and TA Billings. In regard to the 140% R/C ratio for DISCO Services,TransAlta explained that it considered various alternatives to address the shortfall in revenuefrom the four rate classes whose revenue to cost ratios were below 100% (TransAlta Irrigation,REA Irrigation, Transmission Service and Wholesale Service). TransAlta stated that the meritsof each alternative were evaluated in terms of the dollar impact on the rate being over-recoveredand the resulting rate change. TransAlta explained that in the final analysis Rate 4100 shouldmake up the revenue shortfall, since even while experiencing over-recovery of 16% in itsrevenue to cost ratio, Rate 4100 still would enjoy a larger rate reduction than residential, oil andgas, general service or large general service rate classes.

The Board notes that the issue of a higher R/C ratio for Small General Service was discussed inDecision U99035 where it was recognized that the R/C ratio of this rate class was originally136% and TransAlta had proposed to move it to 120%. The Board also notes that its calculationsindicate that changes which it has directed TransAlta to make to its cost of service study in thisDecision will reduce R/C ratio for Rate 4100 to about 105%.

The Board agrees with the views of PICA and MI that an inequity to Rate 4100 customers wouldexist if the refiled numbers were accepted. The Board would have directed changes to other rateclasses had this situation not changed. However, the Board calculates, that the changes orderedin this Decision will result in an approximate revenue/cost ratio of 105% for Rate 4100.

Therefore, in the Board’s view Rate 4100, as adjusted to reflect the changes ordered in thisDecision, will be consistent with the rate design criteria established in Decision U99035.



15. MAXIMUM INVESTMENT FOR RESIDENTIAL SERVICES

In Decision U99035 the Board directed TransAlta to contribute to a maximum investment levelof $1,660 for each new residential underground service and $820 for each new standardoverhead service in TransAlta’s service area. TransAlta’s proposal had been for a residentialinvestment level of $1,660 in Sherwood Park and St. Albert and $820 for all other residentialcustomers. In its refiling TransAlta questioned the disparity created by the Board’simplementation of two levels of maximum investment for residential customers. TransAltarequested, in its refiling, that the Board approve the residential investment level of $820 perservice, for both underground and overhead service.

The REA/AAMDC stated that this matter would more appropriately be dealt with through anR&V application. The REA/AAMDC noted that TransAlta’s current proposal on the maximuminvestment level for residential customers was generally the same position as that taken by theREA/AAMDC in its Phase II argument. The REA/AAMDC stated that there was insufficientevidence to support the difference in investment levels in underground subdivision facilitiesrelative to overhead facilities as had been proposed by TransAlta. The investment level needs tobe revenue based and if there are insufficient savings on underground services relative tooverhead services to justify the higher investment then the investment level should not beincreased. The REA/AAMDC stated that this would unfairly impact residential customers servedby overhead lines. The REA/AAMDC submitted that, if there is no cost savings in undergroundfacilities relative to overhead facilities, there should be no differential in investment levels.

The CCA stated that it was inappropriate to make changes to the Board’s specific directions onthis matter without applying for a review and variance. The CCA noted that making changes ininvestment levels also affects the rate base as these investment levels would be reflected inTransAlta’s rate base. The CCA stated that there was a need to examine whether or not therereally is a difference in the O&M expense for underground as opposed to overhead services. TheCCA submitted that it was inappropriate to not comply with the Board’s directions on thismatter.

The MI noted that TransAlta did not comply with the Board’s direction with respect to this issue.The MI noted that, in Decision U99035, the Board stated that TransAlta did not provide anyevidence to indicate that the costs of constructing underground facilities in new subdivisions inSherwood Park and St. Albert is any different in other municipalities served by TransAlta.

The MI stated that it was not relevant whether or not the ongoing O&M costs for undergroundservices are lower than for overhead services. The MI suggested that the costs associated withoverhead facilities in an urban residential subdivision were an anachronism.

The MI noted TransAlta’s concern that a disparity is created, as the same rate will be chargeddespite receiving different levels of investment. The MI stated that this was a transitional matter,at best, as there are no new overhead installations in urban residential subdivisions. The MI

15. MAXIMUM INVESTMENT FOR RESIDENTIAL SERVICES TransAlta 1996—Phase II Refiling


noted that the disparity arose due to TransAlta’s proposal to increase the residential investmentlevel in Sherwood Park and St. Albert to an amount equal to the cost of construction whileignoring other urban communities in its service area. The MI noted that the previously approvedamount of $1760 per service had been in place for approximately 10 years and did not reflecteither cost increases over that time or that all new urban residential services are required to beconstructed underground.

The MI noted TransAlta’s comment that approximately 30% of new residential customers stillreceive overhead service. In response, the MI noted that 30% of overhead service representsservice to rural customers for whom underground service is neither practical nor appropriate. Inresponse to TransAlta’s comment that a higher investment level provides only an indirect benefitto most customers, the MI stated that there was no evidence that developers retain the increasedinvestment. Further, the MI submitted that there was no evidence that the amount of theinvestment only goes to developers as opposed to municipalities, which develop land andindividual buyers.

The MI requested that TransAlta respond to the direction provided by the Board on this issue.

TransAlta acknowledged that the Board determined cost-of-service evidence supporting reducedoperation and maintenance costs due to customer density in these large urban centres did notsubstantiate the increased investment level in the two communities. However, TransAltasubmitted that there is no evidence that the ongoing operation and maintenance costs forunderground residential services are lower than for overhead services, either in these twocommunities or elsewhere.

TransAlta stated its concern that by having an investment level of $1,660 per service for allunderground services and $820 per service for all overhead residential services, there is adisparity created between new overhead and new underground services. TransAlta stated thatunderground and overhead services will be charged the same rate despite receiving differentlevels of investment and without any evidence supporting different operation and maintenancecosts. TransAlta requested that the Board approve the residential investment level of $820 perservice.

Board Findings

The Board did not accept TransAlta’s position with respect to maximum investment levels forresidential services in Decision U99035. TransAlta was directed to contribute a maximuminvestment level of $1,660 for each new residential underground service and $820 for each newstandard overhead service. In its refiling TransAlta argued that it was more appropriate to have amaximum investment level of $820 for each new residential service.

The Board notes TransAlta’s argument in its refiling that the Board’s finding in DecisionU99035 created an inconsistency. The inconsistency results as some residential customers will

15. MAXIMUM INVESTMENT FOR RESIDENTIAL SERVICES TransAlta 1996—Phase II Refiling


receive a maximum investment level of $820 and others receive the maximum investment levelof $1,660 yet all customers are subject to the same rates.

Generally, it would be expected that a difference in investment levels for two customersreceiving the same service would then see the difference in investment level reflected in therates. An individual residential customer is receiving the same service regardless of whether thelines delivering that service are overhead or underground. Therefore, the Board agrees withTransAlta that two different investment levels for the same service creates an inequity betweencustomers within a rate class unless the different investment levels reflect evidence supportingdifferent operating and maintenance costs within the rate class.

Having decided that there should be only one investment level, it is necessary to determine whatthat appropriate level should be. The Board notes TransAlta’s comment that the higherinvestment level proposed for Sherwood Park and St. Albert was based on lower operation andmaintenance costs associated with more densely-populated service areas, and was not based onlower operation and maintenance costs for underground versus overhead services. As the costsfor rate classes are, by nature, blended amongst the various characteristics in the rate class, itwould be expected that, by including St. Albert and Sherwood Park in the mix in determining anappropriate investment level, the result should be something between the $820 and $1,660. TheBoard expects that the total for all residential customers would be closer to the $820 than the$1,660. Absent the data to calculate an appropriate amount at this time, the Board considers thatthe $820 is an appropriate investment level for all residential customers at this time.

The Board expects TransAlta to revisit the appropriate investment levels for residentialcustomers at the time of its next GTA.

Therefore the Board, acting on its own initiative, will vary its findings in Decision U99035 sothat the maximum investment level for residential service in TransAlta’s Terms and Conditionsof Electric Service will be $820 per service. Further, the Board finds that the Terms andConditions of Electric Service approved by the Board in Decision U99035, on an interim,refundable basis effective November 1, 1999, are to be considered as final as of that date.



16. REA AND FARM RATES – RATE 2100 TO RATE 2500

The REA/AAMDC submitted that a company farm transmission rate including a capacity chargewas not proposed by any party to the Phase II and that TransAlta’s inclusion of such a charge inthe refiling did not appear to respond to any direction made by the Board.

The REA/AAMDC also noted that the upstream rates (generation and transmission) for bothTransAlta’s farms and REA farms have been the same for many years and were based on anenergy charge. In the refiling, there is a significant difference between the REA rate and theTransAlta Farm rate. The REA/AAMDC submitted that the refiled rates were inappropriategiven the competitive position of REAs and TransAlta. REA/AAMDC requested that the Boarddirect TransAlta to design the generation and the transmission portion of farm rates for REA andTransAlta so that they are identical.

While supporting the Board’s initiative to move to cost based rates, the REA/AAMDC submittedthat there needs to be some recognition of the imprecision in cost of service studies. TheREA/AAMDC submitted that TransAlta had indicated that it would consider making thegeneration charge equivalent but not the transmission charge.

The REA/AAMDC explained that TransAlta attempted to justify the difference by noting that35% of REA’s customers are served on 8 kV line while only 21% of TransAlta’s customers areon 8 kV line. It was referenced that TransAlta indicated that losses are higher on 8 kV lines. TheREA/AAMDC considered this extremely tenuous evidence not supported by any load researchstudy they were aware of. The REA/AAMDC had not addressed the matter in the Phase IIproceeding since in TransAlta’s original rate proposal it was not an issue.

The REA/AAMDC noted that AE and TransAlta had used the same losses for REAs andCompany farms since a 1986 proceeding. The REA considers that made sense since farmers canand do switch between REA and Company systems. The REA/AAMDC submitted havingdifferent losses might lead to inappropriate geographical rate differentiation.

The REA/AAMDC also noted that AE proposed refiled REA and Company Farm rates whichinclude an identical capacity component for transmission and submitted that if TransAlta cannotget certain kVA data for certain REAs, then it should design an energy only based rate for allfarm customers. Otherwise the refiled Company farm rate for larger, high load factor customersis better than the REA rate as shown in REA/AAMDC.TAU-1. There is considerablecompetition for the larger load.

The REA/AAMDC also requested that the Board direct TransAlta to provide a REA large farmrate and a REA grain drying service rate, which would allow the REA’s to offer the rate optionswith the same benefits TransAlta can offer to its large farm customers.

16. REA AND FARM RATES – RATE 2100 TO RATE 2500 TransAlta 1996—Phase II Refiling


The REA/AAMDC submitted that while they had raised all of the above matters in the Phase IIproceeding, they had not pursued them due to TransAlta’s responses at the time, which accordingto the REA/AAMDC’s understanding, made the matters non-issues. However, the refiled rateshave changed matters in such a way as to reawaken the REA’s concerns.

TransAlta noted that the REA/AAMDC positioned the REAs as ‘competitors’ of TransAlta, andrequested rate changes to enhance such competition. TransAlta submitted that the fact that REAsand TransAlta are wires owners with overlapping service areas does not lead to a need foridentically designed generation and transmission rate elements if there are valid reasons fordifferences. TransAlta submitted that the following were valid reasons for differences:

TransAlta designed the TransAlta Farm, the REA Farm, and all other rates based on cost and setthe revenue-to-cost ratio at 100% for Energy Supply (generation) and TA Billings (transmission)as directed by the Board.37 The cost to serve each component (Energy Supply, TA billings,DISCO) for the TransAlta Farm rate class is not identical to that of the REA Farm rate class.Therefore the charge for each of the generation and transmission components is not identical.

TransAlta designed its rates, including TransAlta Farm Rate 2100, with an energy and demandcharge for the transmission component, to closely reflect TA Billings to TransAlta. The REAFarm Rate 2400 transmission component is designed with an all energy charge since demandreadings are not readily accessible for billing REA members in all cases; seeREA/AAMDC.TAU-1.

TransAlta did, however, maintain an identical total energy charge of 4.23¢/kWh for each ofTransAlta Rate 2100 and REA Farm Rate 2400 as follows:

TransAlta Farm Rates Comparison (Refiling)

Rate DesignComponent

TransAlta FarmRate 2100

(cents/kWh)

REA FarmRate 2400

(cents/kWh)Energy 3.56 3.61Regulated Generation Credit -0.61 -0.61Transmission 0.80 1.23Distribution 0.48 -Total 4.23 4.23

TransAlta submitted that there is no reason to redesign the two rates to be identical for thegeneration and transmission components as the revenue to cost ratio for each component is 100%and the energy charge in total is identical.

37 Decision U99035, p.74



TransAlta also submitted that the need for an REA large farm rate was reviewed in the Phase IIproceeding. The reasoning offered by TransAlta at that time (which are summarized inREA/AAMDC’s submission) was not affected in any manner by Decision U99035 nor byTransAlta’s subsequent Refiling. Therefore, the issue does not fall within the scope of anexamination of the Refiling.

TransAlta submitted that the “supposed issues” of load research and losses, which theREA/AAMDC raised and their impact on the design of the rates were raised in a “belatedmanner.” TransAlta submitted that, to the extent these items have any valid bearing on thesematters, they could have been raised in the Phase II proceeding leading to Decision U99035, anddo not form proper considerations in the examination of the Refiling.

Board Findings

The Board considers that the issues with respect to Farm rates to be decided in this Decision areas follows:

• Has TransAlta developed a rate structure that is cost based for both generation andtransmission?

• Has TransAlta removed the cross subsidization of TransAlta DISCO rates throughmaking the rates cost based and is there a valid reason for a different rate structurebetween TransAlta Farm and the REAs?

• Whether there is a valid reason for all rate options not being available to both rateclasses?

Before addressing the first question, the Board will first outline some of the original issues.

In the original proceeding, the REA/AAMDC did raise concerns about the approach thatTransAlta was taking in its rate structure and that the potential competitive advantages thatTransAlta would have over the REAs as a consequence. There was further concern expressedabout the impact that rate structures will have on the potential for TransAlta to acquire REAs inthe transition toward restructuring. The Board considers that the choice for a REA to sell toTransAlta or any other entity is a business decision that its members are free to make. However,the rate structure proposed by TransAlta should not give it a competitive advantage over theREAs and should not interfere with normal business and commercial decisions of REAmembers.

With respect to the first issue, the Board directed TransAlta in U99035 to develop rates that werecost based so as to correct the significant cross subsidization of DISCO services by the TABillings component that was revealed in that proceeding. The Board considers that TransAlta’sREA rates should reflect the costs TransAlta faces to serve the REAs. The Board notes thatTransAlta stated that both its Farm and the REA Farm customers pay the same amount forgeneration and transmission.



The rate structure proposed by TransAlta is different for the REAs than for TransAlta Farm rates.However, the Board notes that if the Farm Rate were moved to a pure energy rate thetransmission cost would be 1.20 cents/kWh which is only slightly less than the 1.23 cents/kWhin the REA Farm rate.

The Board notes TransAlta’s explanation that the higher losses on the typically lower voltageREA lines are the cause of the differential, although the Board notes that the data supporting themagnitude of the losses has not been filed. The Board considers that the scope of the REA’ssubmission regarding load research is too extensive to address in this forum and must await theDistribution Tariff proceeding wherein transmission and distribution system costs of the DISCOswill again be examined in detail. Accordingly, at this time, the Board will accept TransAltaexplanation for the difference in rates and that TransAlta has developed rates that are cost based.However, the Board directs TransAlta DISCO to submit its technical support for the claimedhigher loss rates at the upcoming Distribution Tariff proceeding.

With respect to the second issue, the question that must be answered is what rate structure wouldbe a reasonable outcome of correcting the significant cross-subsidization of TransAlta DISCOservices by setting the revenue-to-cost ratio for generation and transmission at 100%.

The Board considers it would be reasonable to expect to observe a lower total rate per unit ofenergy proposed for the REAs than for TransAlta Farm. It would be reasonable to expect thatthis difference would be equivalent to the amount of the DISCO service charged to TransAltaFarm customers since the REA do not receive this service. This would be fair to REA customerswho pay for the equivalent of DISCO services through their own system. The Board furthernotes that AE has designed equivalent rates for both REA and AE Farm rates. By contrast, theBoard notes that the energy rates for both TransAlta Farm and the REAs are conveniently equalon a per kWh basis although TransAlta Farm customers also have a fixed monthly demand rate.The Board considers that the TransAlta Farm rate could be more attractive for larger customersthan the structure available to the REAs. Both TransAlta DISCO and the REAs desire largercustomers.

Therefore, the Board considers that TransAlta’s redesigned rates do not meet the Board’sexpectations for removing the cross subsidization of TransAlta DISCO. The Board considers thatrate structure advantages have been built into the DISCO rate structure. The Board furtherconsiders that there is no valid reason for a different rate structure between the two Farm rates,based on the information submitted. The Board agrees with the REAs approach to resolving thisissue. Accordingly, the Board directs TransAlta to redo its rates, in a second refiling, so that anidentical capacity component for transmission exists for both the TransAlta Farm and the REArates or alternatively, to develop an energy only based rate for all Farm customers if TransAltacannot get the necessary kVA data for certain REAs.



With respect to the third issue, the Board considers that TransAlta may be attempting to enhanceits competitive position by offering TransAlta’s larger customers the new Grain-Drying Servicerate without offering the same rate to REAs. The Board considers that TransAlta should offerREA customers a similar rate, only with a slightly higher charge appropriate to collect for anynecessary higher losses. Similarly, the Board considers that TransAlta should continue to makeavailable a Large Farm rate to the REAs. Accordingly, the Board directs TransAlta, in a secondrefiling, to create an equivalent to the Grain-Drying Service rate and the Large Farm rate forREA customers using the principles in this section of the Decision.



17. ADEQUACY OF INFORMATION RESPONSES

IPPSA/SPPA38 states: “TransAlta should be directed to provide the actual 1998 billingdeterminants for the rate 6100 class in order for the Revenue under Existing rates numberssubmitted to be verified. This information was requested in IPCAA.TAU-12 andIPPSA/SPPA.TAU-3, but was not provided.” Similarly, IPPSA/SPPA states:39 “The Boardshould direct TransAlta to provide the actual 1998 billing determinants for all rate classes inorder for the Revenue under Existing rates estimates submitted to be verified.”

IPCAA noted that it had asked TransAlta to provide data showing the impacts on actualcustomers of its re-filed rates.40 TransAlta responded by providing illustrative examples; each ofwhich is presented on a monthly basis. IPCAA submits that the examples are unrepresentativebecause they either fail to account for actual customer behavior or are based on unrealistic(implicit) assumptions. More specifically, the TransAlta examples do not capture the impact ofmoving from Rate 790 (a heavily demand-based rate which incorporated an 85% ratchet) toTransmission Service Rate 6400 (a predominantly energy based rate for which the demandcomponent is now subject to a 100% ratchet).

IPCAA’s analysis, based on assessing existing versus re-filed rates (over 8760 hours) indicatesthat for a 60% load factor load customer, expected rate decreases of eight per cent (calculated ona monthly basis) can actually result in a nil decrease on an annual basis. At an 80% load factor,calculated monthly increases of two and one-half per cent can result in an eight per cent increaseover a year.

The outcome depends upon how the load factor is achieved. The monthly calculations providedby TransAlta (and this is equally true of AE) implicitly assume that the same peak is achievedevery month and the same load factor is achieved every month. TransAlta provided suchillustrative rate impact calculations in the response to TCE.TAU-2.

IPCAA submits that it would be both unfair and unreasonable if the Board were to rely onassessments of rate impacts based on single month calculations to determine “acceptable”customer impacts. For this reason, TransAlta (and AE) should be directed to provide data in theform requested in IPCAA.TAU-14 in order to provide a realistic assessment of the re-filed rates.

TCE.TAU-2 requested many comparative analyses be performed for Rate 6400 and repeated forDirect Connected Service Rate 6410. TransCanada submitted that TransAlta’s responses wereinadequate. TransCanada submitted that as illustrated in TCE.TAU-2(c), that TransAlta’s“conclusion about the closeness of the two rates” applies only to the one customer with specificload characteristics and cannot be generalized to the whole rate class.” TransCanada also

38 p.839 p. 340 IPCAA.TAU-14

17. ADEQUACY OF INFORMATION RESPONSES TransAlta 1996—Phase II Refiling


submitted that contrary to TransAlta’s indications the IPCAA.TAU-14 does not respond toTransCanada’s request for information categorized by steps in load and load size for each of6400 and 6410.

TransAlta noted IPCAA’s41 statements that: “Rate comparisons on a monthly basis aremisleading,” “unrepresentative,” “fail to account for actual customer behavior,” “are based onunrealistic (implicit) assumptions,” and “do not capture the impact of moving from Rate 790…to Rate 6400…”.

TransAlta responded by noting first that the billing determinants used for all rates, includingRate 6400, are based on monthly demand and energy consumption, blocked appropriately for theproposed rate with the actual monthly demands adjusted to billing monthly demands, given theratchet proposed for the rate. Based on this traditional billing determinant process, TransAltasubmitted that the revenue calculation under the proposed rate was realistic and representative,and that the percentage rate increase, in fact does capture the impact of the change from Rate 790to Rate 6400.

Moreover, in seeking to explore the impact on individual customers, TransAlta provided therequested table in response to IPCAA.TAU-14. TransAlta noted with only 52 customers and thetable has 42 cells, it was inevitable that several cells would contain a single customer. The ninecells that did were masked to preserve the confidentiality of the exact customer information.Similarly, other cells were masked to prevent the individual customer data being derived bydifference. However, TransAlta considers that the table still met the request, and does allow for areconciliation to Table Rates A-1.0 Refiling. The overall increase for the rate class was close to10% (given the provisos at the foot of the table), and the individual rate changes range fromminus 42% to plus 18%.

Further, TransAlta provided illustrative examples in Information Responses ACD.TAU-3 andTCE.TAU-2, which showed explicit calculations for a 10 MW customer with a 90% load factor,a 50 MW customer with a 55% load factor, and a 60 MW customer with a 98% load factor. Theassumptions behind these calculations were provided in full, and the summary results areextended for a range of loads from 10 MW to 100 MW and for a range of load factors from 50%to 98%. These tables show a range of rate changes from minus 20% to plus 17%, which togetherwith IPCAA.TAU-14, aligned to the overall rate class increase of 10%.

TransAlta submitted that IPCAA claims for a 60% load factor customer and an 80% load factorcustomer, evaluated over 8760 hours, were unsubstantiated with no detail regarding assumptions.TransAlta submitted that considering the substantive and consistent nature of the evidence ofTransAlta, it should be apparent that IPCAA’s claim that it would be “both unfair andunreasonable” for the Board to rely on TransAlta’s detailed assessments of rate impacts, isunsubstantiated.

41 p.7



TransAlta noted that it had provided responses for Rate 6400, and added that since Rate 6410 hasidentical generation charges and very similar transmission charges, the results could begeneralized for the whole rate class. TransAlta did not provide an actual comparison for a rangeof customer loads and load factors, the information in response Table TCE.TAU-2(c) showed thefollowing monthly transmission charges under the rates:

Transmission Charges (per TCE.TAU-2)

Rate 6400 Rate 6410 Fixed/Demand charges $ 93,500 $ 93,950 Variable/Usage charges $176,400 $182,180*

*the same On-peak and Off-peak energy was used in both calculations forsimplicity. In fact, the TA has no On-peak energy on statutory holidays, so theRate 6410 charge would actually be lower.

The fixed and variable transmission charges are very close for the example provided. TransAltaconcluded that where both the level and the structure of the rates were very similar, the resultcould be generalized; meaning in particular that over a range of customer load sizes and loadfactors, the transmission charges under rate 6400 or rate 6410 would be similar. Further, sincethe generation charges under the two rates are identical, TransAlta concluded that total chargesunder both rates would be similar. Therefore, the rate comparisons provided in TCE.TAU-2 (a) and (b) for a wide range of possibleload and load factor customers may be applied to both rate 6400 customers and rate 6410customers. Further, TransAlta concluded that the results provided in response IPCAA.TAU-14,for all of the Rate 6400 series customers, would render no additional comparative priceinformation if separated into 6400 and 6410. TransAlta noted that TransCanada professed uncertainty as to who qualifies for or must takeRate 6410. TransAlta submitted that TransCanada must have ignored Clauses 6 and 7 of theTerms and Conditions and page 8 of the Rates evidence in the Refiling, in order to make such astatement. TransCanada also suggested that it was unclear whether TransAlta intends to applythe TA’s time of use periods for Direct Connected Service, or the periods from TransAlta’s rates.Since TransAlta has been directed to pass through the TA’s charges to Direct ConnectCustomers, those charges will perforce reflect the TA’s time of use parameters.

In TransCanada-TAU.2 (a), TransAlta was requested to confirm the accuracy of the results oftwo TransCanada calculations, without the benefit of seeing the calculations or assumptionsbehind them. TransAlta re-created the TransCanada calculations are far as it was able, and



provided the comparative answer and a qualification. In its Submission:42 “TransCanada submitsthis approach…. is inadequate in the New World,” and goes on to imply that TransAlta shouldhave performed the calculation with “hourly information” and “pinpoint accuracy”.

TransAlta submitted that this was all a far cry from the original request. In any event, TransAltaalso provided the comparative rate calculations for a wide range of possible load sizes and loadfactors. Further, in the Table attached to IPCAA.TAU-14, TransAlta provided a reconciliation ofthe increases for all actual individual customers, aggregated by load size and load factor, to theincrease for the rate class as a whole. Board Findings

The Board accepts that TransAlta’s calculations may not have provided the detail or the methodthat IPCAA and TransCanada desired, but the Board accepts that TransAlta appropriatelyresponded to the information requests filed. TransAlta has provided enough information for theBoard to decide the issues related to Transmission Service Rate 6400 and Direct ConnectedService Rate 6410 and other industrial rates.

The Board agrees with TransAlta that the refiling process requires only a comparison of therefiled rates to the existing rates and not to the rates that TransAlta originally applied for. TheBoard considers that the requested rate comparisons would appear to be directed towardsbuilding a case for an R&V. Further, the Board considers that the IPCAA, ACD andTransCanada submissions, and the information responses, do indicate the extent of the increasesfor the high load factor customers. The Board considered those increases in the section on Levelof Rate Increases.

42 p.3, item 4



18. PAYMENT OF INTEREST TO THE CITIES

In Decision U99035, the Board directed TransAlta to provide, in its refiling, a calculation of itsinterest refund and a proposed rider to refund the interest to customers. By letter datedSeptember 14, 1999, ENMAX and the Cities of Lethbridge and Red Deer (jointly referred to asthe Cities) noted that the entitled distribution utilities such as the Cities are customers ofTransAlta, with respect to the reservation and transmission facilities payments. Therefore theCities, along with other entitled distribution utilities are entitled to a refund of interest inaccordance with the Board directed calculation.

In its refiling of October 4, 1999, TransAlta stated that it did not agree that interest should bepaid to the Cities as they were no longer customers of TransAlta.

The Cities filed an application on October 13, 1999 to review and vary Decision U99035 withrespect to the matter of interest payment. The Cities calculated that there was a refund of $49,100,000 related to TransAlta’s GENCO and$38,500,000 related to TransAlta’s TRANSCO in each of 1996 and 1997. On this basis, theCities stated that they were entitled to an interest payment of $1,947,000 due to overpayments toTransAlta’s GENCO and $1,542,000 due to overpayments to TransAlta’s TRANSCO. The Citiesstated that these amounts are material and therefore TransAlta should be required to make apayment of interest to the Cities.

The Cities acknowledged that they received loan advances from AE, TransAlta and EPCOR,which have since been repaid. The Cities stated that they would expect to pay interest on thoseadvances in accordance with the methodology used in this application to calculate the interestpayment requested from TransAlta.

TransAlta did not agree that interest should be payable to the Cities. TransAlta noted that theCities were no longer customers of TransAlta’s entitled distribution system in 1996. TransAltafurther noted that that all utilities, including the Cities, reached a comprehensive settlement on alloutstanding balances stemming from the 1996 Phase I decisions and the 1997 negotiatedsettlements. This settlement was filed with the Board under cover of letter from Dr. GuyBridgeman of EPCOR on June 4, 1998.

Board Findings

In Decision U99035, the Board determined that TransAlta should pay interest on the amountsthat it had over-collected in 1996 and 1997 from its DISCO customers. The Cities have requestedthat interest should also be paid on the changes in TransAlta’s GENCO and TRANSCO revenuerequirements, as these were material changes. Interest is awarded on over-collections torecognize that shareholders have the use of “customer’s money” over an extended period of time.

18. PAYMENT OF INTEREST TO THE CITIES TransAlta 1996—Phase II Refiling


Conversely, interest would be collected from customers if there were under-collections fromcustomers over an extended period of time

If the Board were to require the TransAlta GENCO and TRANSCO functions to pay interest onover-collections, approximately 40% of this interest refund would accrue to the TransAltaDISCO. TransAlta shareholders would be neutral with respect to that portion of the interestrefund. Nevertheless, TransAlta shareholders would be required to fund the remaining interestrefund to the other investor and municipally owned DISCOs. The Board considers that thiswould not be fair unless all GENCO and TRANSCOs (including non-regulated municipallyowned TRANSCOs) were subject to the same wholesale interest guidelines with respect tochanges in their wholesale costs. In the absence of such a wholesale interest process, the Boardconsiders it fair and appropriate that the interest guidelines apply to regulated retail operationsonly.



19. ELIGIBILITY FOR RATE 2800 – REA IRRIGATION SERVICE

The South Alta Rural Electrification Association Limited (SAREA) filed an application onOctober 29, 1999 with the Board on behalf of a group of customers.

The application requested that those irrigation customers served by TransAlta in the SAREAservice area:

• who expressed a desire to transfer their irrigation services, or• who are in the process or transferring their irrigation services to SAREA, or• who are presently constructing irrigation services but who will not be taking service until

after October 31, 1999

be allowed to take service on Rate 2800 – REA irrigation service (closed), the grandfatheredrate.

SAREA filed this application because several TransAlta irrigation customers have beenattempting to transfer their services to SAREA. However, a dispute over the method ofcalculating the cost of transfer has prevented transfers from proceeding. The dispute arose inOctober 1997.

TransAlta has stated in the Refiling that, “this rate is only available for services that were billedon an REA irrigation rate as at the end of the 1999 irrigation season.” The 1999 irrigation seasonends October 31, 1999.

SAREA wishes to ensure irrigation customers who have been awaiting the resolution of themethod of calculating the cost of transfer dispute will be entitled to take service at Rate 2800when such transfers have been accomplished. SAREA requested the ability to grandfather thesecustomers even if such transfers take place after October 31, 1999 by making this problemknown to the Board prior to October 31, 1999.

Additionally, there are a limited number of REA members who are in the process of havingirrigation services constructed. SAREA submitted that those members who commencedconstruction of irrigation services under the rate structure that existed prior to October 31, 1999should also be allowed service on Rate 2800.

The SAREA application was filed on behalf of: Silver Top Dairies Ltd., Granum ColonyHutterian Brethren, Pan Prairie Dairy, Hill Top Dairy, A & M Van Driesten, Brobbel Farms,James Vandervalk, Klaas Veenland, Doug Ashley, Massey Farms, Hansma Farms, DaveMacnab, Calderwood Jaola Ranches, and Hurlbert Ranches.

In Decision U99035, the Board noted the large increase proposed for the REA Irrigation Rate. Inthe interest of giving the appropriate price signal to customers who are assessing whether or not

19. ELIGIBILITY FOR RATE 2800 – REA IRRIGATIONSERVICE



to invest in electric irrigation pumping equipment, the Board allowed an increase in the newREA Irrigation Rate that was greater than the 10% cap. However, the Board grandfathered thosecustomers currently on the rate thereby allowing rate increases to these customers to be increasedmore moderately over time. The Board’s intent was that, over time, this rate should be broughtup to a level where it more closely approximates a 100% revenue-to-cost ratio.

Pursuant to the Board’s direction in U99035, TransAlta proposed to close Rate 2800 to all butexisting REA irrigation customers presently taking service under this rate. Rate 2800 was limitedto a 10% increase in revenue-to-cost ratio and a new Rate 2810 was created with a revenue-to-cost ratio of unity for new REA irrigation services.

The REAs noted that SAREA has continued to deal with TransAlta to resolve the problem ofcustomer transfer cost calculations. SAREA filed its application to preserve the right of irrigationcustomers who would have been taking service under Rate 2800 had this issue been resolved.The REAs therefore submitted that these customers should be allowed the benefits of Rate 2800.SAREA requested that Rate 2800 be available to the customers, on whose behalf the applicationwas filed, for a period of one year following the resolution of the issue of the method ofcalculating the cost of transfer between TransAlta and SAREA. The REAs submitted thatapproval of the SAREA request would have little impact on other customers in the TransAltaservice area because of the limited scope of the application.

The REAs noted the Board’s comment in Decision U99035 that an appropriate price signalshould be given to customers assessing whether or not to invest in electric irrigation pumpingequipment. The customers on whose behalf the SAREA filed its application made the decision tobegin the transfer process or construct facilities prior to the functionalization of any applicablerate. There are 14 customers listed in the SAREA application and SAREA has worked on fournew irrigation services prior to October 31, 1999. These services will not be energized prior tothe next irrigation service.

The REAs noted that total revenues forecast from this rate class only amount to $15,000. TheREAs further noted that neither the specified irrigation customers nor SAREA would have beenaware when they made the decision either to transfer or construct services of the proper costsignals. Therefore, the REA submitted that it would be fair to grandfather those customers listedin the SAREA application and the other four for whom the REA was constructing facilities priorto October 31, 1999. This would serve to specifically identify those to whom grandfatheringapplies and any dispute over whether or not TransAlta had received a request to transfer. TheREA stated that the only problem that would remain would be to ensure that negotiations withrespect to customer transfer and the cost thereof would not be delayed past a certain date. TheREA recommended that, if an agreement is not reached by February 1, 2000, an employee of theBoard be appointed to mediate pursuant to section 66(b) of the EU Act.

19. ELIGIBILITY FOR RATE 2800 – REA IRRIGATIONSERVICE



Board Findings

The Board notes that, in this case as is so often true, the imposition of a date where customers areconsidered to be grandfathered on a more favourable rate leads to questions of whether othercustomers should be eligible to receive the grandfathered rate. The Board considers it necessaryto look at the intent of its finding in Decision U99035 to determine whether or not the customersin question are eligible to receive the grandfathered rate. The Board notes the low level ofrevenues forecast from this rate and considers that this issue will not be determined out ofconcern for the total revenues collected from this rate class.

It is quite clear that, in making its finding in Decision U99035, the Board was attempting tobalance competing interests. On the one hand, the Board wanted to avoid rate shock to existingcustomers and therefore imposed a maximum 10% rate increase. However the Board was alsoconcerned that, by continuing to accept a low revenue-to-cost ratio for this rate class (forecast tobe 63% in TransAlta’s refiling) there was a danger that customers could choose to enter into aservice based on a cost structure that could change dramatically, potentially as early asJanuary 1, 2001. Therefore, it concerns the Board if the customers represented by the SAREAapplication find that the service they are pursuing is economic only under the closed Rate 2800,when these customers will face the rate level of Rate 2810 in the not-too-distant future. TheBoard accepts, however, that there is an inherent unfairness to those customers who had alreadymade the decision to pursue service under Rate 2800 and, through other circumstances, were notyet signed up when the Board’s decision was issued. Although Decision U99035 was issuedAugust 10, 1999, TransAlta has allowed any customers who were taking service on Rate 2800,through the end of the irrigation season, October 31, 1999, to be grandfathered. Since mostirrigation customers likely begin service near the start of the irrigation rather than in the midst ofthe season the Board expects that grandfathering customers on the rate through the end ofOctober 31, 1999 likely covered the customers in question.

The Board, therefore, agrees to allow the customers included in the SAREA request to becovered in the grandfathering of Rate 2800. These customers are: Silver Top Dairies Ltd.,Granum Colony Hutterian Brethren, Pan Prairie Dairy, Hill Top Dairy, A & M Van Driesten,Brobbel Farms, James Vandervalk, Klaas Veenland, Doug Ashley, Massey Farms, HansmaFarms, Dave Macnab, Calderwood Jaola Ranches, Hurlbert Ranches. In argument, the REAsnoted that SAREA was building facilities for four additional customers. These four additionalcustomers, who have not been identified, shall also be considered to be eligible for Rate 2800.Rate 2800 shall remain a closed rate effective the end of the 1999 irrigation season with theseexceptions only.

With respect to the request by the REAs to have a Board employee appointed to mediatenegotiations between TransAlta and SAREA, the Board considers that this request is best dealtwith in another forum and not through this Decision on TransAlta’s refiling. The Board does,however, support the use of Dispute Resolutions techniques as an alternative to hearings and toachieve greater satisfaction amongst the parties.



20. SUMMARY OF BOARD DIRECTIONS

1. Accordingly, the Board directs TransAlta to redo, in a second refiling, its cost of servicestudy implementing the changes below:

• TransAlta’s 1998 RP and total cost of service should be reduced to reflect the DISCO’sshare of the actual surplus/shortfall deferral accounts that was based on actual pool pricesand loads

• TransAlta’s 1998 RP and total cost of service should be reduced to reflect theadjustments for Battle River

• TransAlta’s 1998 energy supply cost and total cost of service should be reduced by theamounts paid out that reflect past year adjustments

• TransAlta should correct the errors identified in IPPSA/SPPA.TAU-5(c) andIPCAA.TAU-11(b) and (f). [Section 3]

2. The Board also directs TransAlta to change, in a second refiling, the refiled rates asnecessary to allow these rates to reflect the new cost of service study, Decision U99035, andthis Decision. [Section 3]

3. Accordingly, the Board directs TransAlta in its second refiling, to allocate the cost of Option10/B credits across all transmission costs so that all customer classes share the costs of thosecredits for the year 2000. [Section 6]

4. However, the Board directs TransAlta to adjust the interim DAT billings from the effectivedate of this Decision onwards to reflect the Board’s Findings to not vary Direction 39 ofDecision U99035. [Section 8]

5. With respect to the implementation of the final DAT, the Board directs TransAlta toincorporate the following provisions:

• To switch all interim DAT customers to service on the final DAT, commencing on thedate that the final DAT is effective.

• To provide, at that time, a one-time option, to all former interim DAT customers to electto switch to another rate within 60 days.

• This one-option is subject to other switching provisions in TransAlta’s Terms andConditions.

• This one-time option is available for a 60-day period, commencing on the date that thefinal DAT is effective.

• If a customer gives notice to switch to another rate, within this one-time 60-day period,the newly selected rate will be effective at the start of the next billing period.

20. SUMMARY OF BOARD FINDINGS TransAlta 1996—Phase II Refiling


• At the completion of this one-time 60 day option period, any former interim DATcustomer who has not elected to switch, shall continue to be served under the final DATand shall be subject to the notice provisions of that rate.

• For additional clarity, after this one-time 60 day period is over, a former interim DATcustomer served on the DAT is required to take DAT service for 6 months before thecustomer may give notice that it elects to be billed under a different tariff. The customermust also give six months notice of the effective date of the change if it elects to be billedpursuant to another tariff.

• For former interim DAT customers, the determination of whether the customer has takenDAT service for 6 months should use the date the customer commenced service under theinterim or TDAT. [Section 8]

6. The Board directs that TransAlta calculate interest on the $9.61 million over the periodJuly 1, 1998 to November 1, 1999. [Section 13]

7. The Board directs TransAlta to calculate the interest using the Bank of Canada rate plus1½%. [Section 13]

8. However, the Board directs TransAlta DISCO to submit its technical support for the claimedhigher loss rates at the upcoming Distribution Tariff proceeding. [Section 16]

9. Accordingly, the Board directs TransAlta to redo its rates, in a second refiling, so that anidentical capacity component for transmission exists for both the TransAlta Farm and theREA rates or alternatively, to develop an energy only based rate for all farm customers ifTransAlta cannot get the necessary kVA data for certain REAs. [Section 16]

10. Accordingly, the Board directs TransAlta, in a second refiling, to create an equivalent to theGrain-Drying Service rate and the Large Farm rate for REA customers using the principles inthis section of the Decision. [Section 16]



21. ORDER

Therefore, it is ordered that:

(1) TransAlta Utilities Corporation shall provide a second refiling of its proposed Rates andOptions and its Terms and Conditions of Electric Service, on or before March 1, 2000,incorporating the findings of the Board in this Decision.

(2) TransAlta Utilities Corporation, in its second refiling, shall include a cost of service studyincorporating the findings of the Board in this Decision

(3) TransAlta Utilities Corporation, in its second refiling, shall include the revenue-to-costratios for each rate by cost source (Energy Supply, TA Billings and DISCO Services).

(4) Decision U99035 is amended as required to reflect the Findings in this Decision.

DATED in Calgary, Alberta on February 25, 2000.

ALBERTA ENERGY AND UTILITIES BOARD

B. T. McManus, Q.C.Presiding Member

A. J. Berg, P.Eng.Member

H. Jainarine, FCCAActing Member

APPENDIX 1

ABBREVIATIONS


AAMDC Alberta Association of Municipal Districts and Counties

ACD Albchem Industries Ltd., CXY Chemicals and Dow Chemical Canada Inc.

AE ATCO Electric Ltd. (formerly Alberta Power Limited)

AIPA Alberta Irrigation Projects Association

Board or AEUB Alberta Energy and Utilities Board

CCA Consumers Coalition of Alberta

Cities Lethbridge and Red Deer

CTMPN Chemi-ThermoMechanical Pulp & Newsprint Producers

DAT Direct Access Tariff

DISCO Distribution Company

DOS DISCO Opportunity Service

EAL or ESBI ESBI Alberta Limited

EEMA Electric Energy Marketing Agency

EU Act Electric Utilities Act

GAC Generation Access Charge

GTA General Tariff Application

IPCAA Industrial Power Consumers Association of Alberta

IPPSA Independent Power Producers Society of Alberta

MI Municipal Intervenors

PAR Pool Access Rate

PICA Public Institutional Consumers of Alberta

POD Point of Delivery

APPENDIX 1 CC ABBREVIATIONS


PUB Act Public Utilities Board Act

R/C Ratio Revenue-to-cost ratio

REA Alberta Federation of REAs Ltd.

RP Reservation price/payment

SAREA South Alberta Rural Electrification Association Limited

SPPA Senior Petroleum Producers Association

TA Transmission Administrator

TOU Time-of-use

TransAlta TransAlta Utilities Corporation

TransCanada TransCanada Energy Ltd.

TRANSCO Transportation Company

UOV Unit Obligation Value

APPENDIX 2

REFERENCES


ORDER/DECISION/REPORT NO. DATE PARTICULARS

E95123 December 21, 1995 TransAlta Utilities Corporation (Order –Approvalon an interim basis, tariffs pursuant to section 75of the Electric Utilities Act)

U98093 June 3, 1998 TransAlta Utilities Corporation (Order – 1998Rate Application)

U99034 August 10, 1999 ATCO Electric Ltd. (Decision – 1996 ElectricTariff – Phase II)

U99035 August 10, 1999 TransAlta Utilities Corporation (Decision – 1996Electric Tariff – Phase II)

U99099 November 25, 1999 ATCO Electric Ltd., EPCOR Generation Inc.,EPCOR Transmission Inc. and TransAlta UtilitiesCorporation (Decision – 1999/2000 ElectricTariff – Phase I)

U99105 November 3, 1999 TransAlta Utilities Corporation (Order – Various1996 Electric Tariff - Phase II matters)

2000-1 February 2, 2000 ESBI Alberta Ltd. (Decision - 1999/2000 Phase Iand Phase II)

2000-3 February 1, 2000 TransAlta Utilities Corporation (Decision –1999/2000 Electric Tariff Application – Phase IRefiling)

Decision 2000-11: TransAlta - 1996 Electric Tariff Application - …€¦ · provided its refiling...

Documents

Transcript of Decision 2000-11: TransAlta - 1996 Electric Tariff Application - …€¦ · provided its refiling...