U99035 Decision: TransAlta Utilities Corporation 1996 ...€¦ · commencing 1 January 1996 in Order E95123, dated 21 December 1995. In Decision U97156, dated 19 December 1997, the

Alberta Energy and Utilities Board Decision U99035 Released: Aug 10, 1999 TRANSALTA 1996CPhase II

Decision U99035 Page 1 10 August 1999

TRANSALTA UTILITIES CORPORATION

1996 GENERAL RATE APPLICATION–PHASE II

TABLE OF CONTENTS

1. INTRODUCTION ............................................................................................................... 5 2. COST OF SERVICE STUDY............................................................................................. 7

(a) General ............................................................................................................................7 (1) Appropriate Cost and Pool Price Data for the Cost of Service Study ...................8

(b) Allocation of Costs Related to Generation....................................................................12 (1) Unserved Energy..................................................................................................26 (2) Trading Fees ........................................................................................................27

(c) Allocation of TA Billings..............................................................................................27 (1) Grid Interconnection Services .............................................................................28 (2) Grid Standard Services ........................................................................................31 (3) TransAlta 25 kV Plant .........................................................................................33

(d) Allocation of Distribution Costs....................................................................................35 (1) Distribution Property ...........................................................................................35 (2) Customer Contributions .......................................................................................37 (3) Other Distribution Operating and Maintenance Expense ....................................38 (4) Marketing and Sales.............................................................................................39 (5) Customer Accounting ..........................................................................................41

3. RATE DESIGN.................................................................................................................. 43

(a) Rate Design – Criteria ...................................................................................................43 (b) Rate Levels for 1999 .....................................................................................................52 (c) 100% Demand Ratchet ..................................................................................................54 (d) Time-of-Use ..................................................................................................................58

4. INDIVIDUAL RATES, OPTIONS AND RIDERS......................................................... 62

(a) Rates ..............................................................................................................................62 (1) Bid Temporary Energy Rate C Rate 720.............................................................62 (2) Residential ...........................................................................................................64

(A) Rate 1100 C Residential.............................................................................64 (B) Rate 1200 C Residential Time-of-Use.......................................................67

(3) Farm .....................................................................................................................69 (A) Rate 2100 C Farm Service .........................................................................69 (B) Rate 2200 C Farm Time-of-Use Service ...................................................70 (C) Rate 2300 C Grain Drying Service ............................................................70

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Alberta Energy and Utilities Board Decision U99035 Released: Aug 10, 1999

TABLE OF CONTENTS TRANSALTA 1996CPhase II

(4) REA Farm Service ...............................................................................................71 (A) Rate 2400 C REA Farm Service ................................................................72 (B) Rate 2500 C REA Farm Time-of-Use Service ..........................................72

(5) TransAlta Irrigation .............................................................................................75 (A) Rate 2600 C TransAlta Irrigation Service .................................................75 (B) Rate 2700 C TransAlta Irrigation Time-of-Use Service............................75

(6) REA Irrigation .....................................................................................................79 (A) Rate 2800 C REA Irrigation Service .........................................................79 (B) Rate 2900 C REA Irrigation Time-of-Use Service....................................79

(7) Exterior Lighting..................................................................................................82 (A) Rate 3100 C Street Lighting Service (Investment Option)........................82 (B) Rate 3300 C Street Lighting Service (No Investment Option) ..................82 (C) Rate 3700 C Festive Lighting Service .......................................................82 (D) Rate 3800 C Yard Lighting Service...........................................................83

(8) Small General and Temporary Services ..............................................................83 (A) Rate 4100 C Small General Service...........................................................83 (B) Rate 4200 C Small General Time-of-Use Service.....................................84 (C) Rate 4300 C Small General Temporary Service........................................84

(9) Oil and Gas Service .............................................................................................86 (A) Rate 4400 C Unmetered Oil and Gas Service (Closed).............................86 (B) Rate 4500 C Oil and Gas Time-of-Use Service.........................................88

(i) Appropriate Allocation of Oilfield Costs .......................................88 (ii) Required Metering..........................................................................92 (iii) Meter Totalization ..........................................................................97

(10) Large General Service .......................................................................................102 (A) Rate 6100 C General Service...................................................................102 (B) Rate 6200 C General Time-of-Use Service .............................................102 (C) Rate 6300 C Large General Time-Of-Use Service ..................................102 (D) Rate 6400 C Transmission Service ..........................................................102

(11) Temporary Energy Service C Rate 6600...........................................................104 (12) Real Time Pricing C Rate 6700.........................................................................106 (13) Direct Access Tariffs C Rate 6800....................................................................108 (14) Partial Requirement Service C Rate 0820 .........................................................123 (15) Wholesale C Rate 8100 .....................................................................................123 (16) Shared Use of Overhead Facilities C Rate 9100 ...............................................124

(b) Options and Riders Summaries ...................................................................................130 (1) Option A C Primary Service Credit...................................................................130 (2) Option B C Unused Investment Credits ............................................................133 (3) Option C C Idle Service Option ........................................................................135 (4) Option D C Flat Rate Option.............................................................................138 (5) Option E C Deemed Demand Option ................................................................138 (6) Option F C Planned Interruption Credit ............................................................139 (7) Option G C Planned Interruption Transition Credit ..........................................150



(8) Options F & G C Interruptible Credits ..............................................................155 (9) Option H C Night Use Option ...........................................................................157 (10) Option I C Reactive Power Option....................................................................159 (11) Option J C Bill Reduction Credit ......................................................................159 (12) Option K C Municipal Adjustment Option .......................................................160 (13) Option L C Seasonal Service Option.................................................................160 (14) Generator Adjustment Rider ..............................................................................161 (15) Additional Options Being Withdrawn ...............................................................163

5. TERMS AND CONDITIONS OF SERVICE ............................................................... 164

(a) Residential Investment in Sherwood Park and St. Albert ...........................................164 (b) Investment Levels & Contract Length and Termination Notice .................................166

6. OTHER............................................................................................................................. 173

(a) Interest on Adjustments...............................................................................................173 7. SUMMARY OF BOARD DIRECTIONS...................................................................... 180 8. ORDER............................................................................................................................. 187



APPENDICES

1 PARTIES PARTICIPATING IN THE PROCEEDING.......................................... 3 pages 2 ABBREVIATIONS ................................................................................................. 3 pages 3 REFERENCES ........................................................................................................ 2 pages 4 HOW THE RP ALLOCATION METHOD MAY DISTORT THE POOL PRICE SIGNAL .................................................................................. 2 pages 5 HOW THE METHOD OF ALLOCATION OF UOV REFUNDS MAY DISTORT THE POOL PRICE SIGNAL ...................................................... 2 pages 6 COMPARISON OF DISTRIBUTION INVESTMENT LEVEL PROPOSALS............................................................................................................ 1 page


TRANSALTA 1996—Phase II

1. INTRODUCTION

TransAlta Utilities Corporation (TransAlta) filed its 1996 Phase II application (the Application) with the Alberta Energy and Utilities Board (the Board) on 30 June 1998. A Notice of Hearing was published on 10 July 1998 and served on all parties on the mailing list from TransAlta’s 1996 Phase I General Tariff Application (GTA). The Board heard the Application and intervenor evidence at a public hearing held in Calgary from 26 October to 12 November 1998 before J. P. Prince, Ph.D., B. T. McManus, Q.C., and H. Jainarine, Acting Member. Interested parties participating in the proceedings have been listed in Appendix 1. The applicant and intervenors were required to provide written argument for the Direct Access Tariff (DAT) and Option 12/21 on 23 November 1998 and written reply on 30 November 1998. The remaining part of the written argument was due on 9 December 1998 and written reply on 30 December 1998. Most of TransAlta’s existing customer retail rates had been approved on an interim basis commencing 1 January 1996 in Order E95123, dated 21 December 1995. In Decision U97156, dated 19 December 1997, the Board approved a 1998 interim rate reduction rider that reflected the negotiated reduction in revenue requirement for 1997 effective 1 January 1998. The Board also approved a 1996 refund rider that refunded the revenue surplus in 1996 and 1997 effective for the period 1 January 1998 to 31 December 1998. In Decision U98029, dated 30 January 1998, the Board approved the 1997 distribution revenue requirement of $992,910,000 that reflected the negotiated settlement between TransAlta and its customers. In Decision U98093, dated 3 June 1998, the Board approved the 1998 distribution revenue requirement of $1,003,200,000. In Decision U98193, dated 24 December 1998, the Board approved, on an interim refundable basis, adjustments to the 1998 tariffs, the 1999 Interim Rate Rider and the 1999 Rate Reduction Rider. TransAlta revised the Application for the Cost of Service evidence on 23 October 1998 as a result of concerns identified in information requests and evidence from intervenors. TransAlta, subsequently, filed final Cost of Service evidence dated 2 November 1998 which was entered as Exhibit 48. In this Decision the Board summarizes relevant positions of parties and sets out the reasons for the Board’s findings on significant matters regarding the Application. TransAlta’s proposed DAT was approved on a temporary basis in Decision U99015, dated 8 February 1999. The temporary DAT will cease to be available to new customers as of the date of issuance of this Decision. Decision U99035 Page 5 10 August 1999

1. INTRODUCTION TRANSALTA 1996—Phase II

Also in this Decision the Board finalizes TransAlta’s interim rates in effect from 1 January 1996 until 31 December 1998. The Board also sets out a process to arrive at new interim customer retail rates, tolls and charges forecast to generate TransAlta’s approved 1998 revenue requirement. The new rates will be interim refundable rates since the 1999/2000 TransAlta Phase I proceeding, currently in progress, will determine TransAlta’s 1999 and 2000 distribution revenue requirements.


2. COST OF SERVICE STUDY

(a) General

In its 1996 Phase I proceeding TransAlta forecast that it will incur certain costs to serve its customers (in total the DISCO’s revenue requirement). The purpose of a cost of service study (COSS) is to analyze the costs forecast to be incurred by the DISCO and to allocate those costs to the customer or customer class expected to cause them. The COSS enables rates to be designed which fairly pass through the forecast costs to the appropriate customers. This section will review TransAlta’s methodology used in its 1996 COSS. TransAlta first separated the costs making up its Distribution Revenue Requirement by function:

Generation Costs Transmission Costs Distribution Costs

Second, TransAlta classified the functionalized costs as:

Customer related Demand related and Energy related

Third, TransAlta allocated the classified costs to its customer classes by using allocation factors based on the number of customers, demand contributions (kW) of classes of service and energy sales (kWh) by classes of service. Customer related costs are costs that vary with the number of customers served. Demand related costs are costs that vary with kW demand. Energy costs vary with the kWhs of energy used. TransAlta’s noted that its forecasts of pool price, energy, demand, load profiles and number of customers for the 1996 test year represented an integral part of the Phase I proceeding. TransAlta submitted that it was appropriate to use the 1996 embedded costs as approved in the Phase I proceeding for the purpose of determining the COSS for the Application. TransAlta negotiated a settlement agreement with its customer groups for the purpose of determining its 1997 distribution revenue requirement. Separate cost components were not determined within the negotiated settlement. Instead TransAlta prorated the costs allocated in the TransAlta COSS to the 1997 distribution revenue requirement approved in Board Decision U98029. TransAlta allocated costs to customer rate classes based on TransAlta’s forecasts of pool price, energy, demand and number of customers for the 1996 test year. TransAlta’s forecasts of hourly pool prices, hourly total energy and annual energy by customer rate class were previously examined in the 1996 Phase I proceeding. The hourly load profiles provide hourly energy


2. COST OF SERVICE STUDY TRANSALTA 1996—Phase II

characteristics for each of the customer rate classes. The hourly load profiles, which were utilized to allocate energy costs, were developed from TransAlta’s hourly total energy forecast, load research data and load growth statistics. With respect to demand costs, TransAlta’s forecast of non-coincident peak (NCP) demands for each customer rate class provided the basis for allocation to customer classes. The number of customers were developed using 1995 levels and growth statistics. Forecast customers were used in place of available 1996 actuals to maintain consistency with other customer data such as energy data which represent forecast amounts. The forecast customer numbers provided the basis for allocating customer costs. (1) Appropriate Cost and Pool Price Data for the Cost of Service Study

TransAlta prorated 1996 costs to 1997 levels to determine most of the costs to be allocated to customers. However, TransAlta used a 1998 pool price forecast for the purpose of developing TOU differentials. The 1998 pool forecast was developed in September 1997. The forecast included a 1998 load forecast that was derived by incorporating actual Alberta energy load data together with actual year-to-date actual load for the period up to August 1997. In addition, gas prices utilized in the forecast were based on AECO-C forward gas prices as of August 1997.1 Several intervening parties argued that TransAlta’s COSS was flawed since it utilized potentially out of date costs and allocation factors. One major concern raised during the proceeding was that TransAlta used a 1996 pool price forecast in order to design rates that would go into effect in 1999. With respect to this concern, parties argued that it was inappropriate to use a pool price forecast that was several years old, particularly given the consideration that pool prices have risen dramatically since 1996. Another issue raised was that TransAlta selectively used adjustments to incorporate updated information into the COSS. Position of TransAlta

TransAlta submitted that it was appropriate to use the 1996 embedded costs as approved in the Phase I for the purpose of determining the COSS for the Application. Forecasts of hourly pool prices, hourly total energy and annual energy by customer rate class were examined during the Phase I proceeding. In response to IPCAA’s comments that the 1998 Negotiated Settlement had not been included in the COSS, TransAlta noted that during the preparation of its Application, the 1998 Negotiated Settlements of other parties had not been finalized or approved. When all the 1998 settlements have been approved, TransAlta intended to incorporate them into a single 1998 Rate Rider. TransAlta also confirmed that Clause 7.2 of the 1998 Negotiated Settlement had established a method of handling rate riders. The method prescribed an across-the-board rider to all rates.2

1 Tr.p.492


2 Tr.p.495


TransAlta submitted that in the absence of finalized 1998 Negotiated Settlements and as a result of the stipulation that there needed to be an across-the-board rider requirement, TransAlta’s method of prorating 1996 costs to 1997 levels was an appropriate process. Position of the Intervenors

IPPSA/SPPA

IPPSA/SPPA submitted that it was inappropriate to use a 1996 pool price forecast to design rates that will go into effect in 1999. That approach will effectively distort price signals since they will be retrospective instead of forward-looking. Significant market changes have occurred since the 1996 forecast was created. Major changes have occurred in several key areas. The overall magnitude of pool prices had increased substantially from 1996 to 1999 (as indicated in a pool price forecast prepared by Optimum Energy Management in IPPSA/SPPA’s evidence). The average annual pool price is forecast to increase from $13.10/MWh in 1996 to $29.60/MWh in 1999, more than a doubling in the price. Overall pool prices have risen considerably as a result of growing load conditions, an expanding need for higher marginal cost units and limited competition in generation. Since1996 tightening market conditions have contributed to a larger number of price spikes, a significant rise in pool prices and greater TOU differentials between peak and off-peak pool and between seasons. Using a 1996 pool price forecast in the COSS effectively distorted the overall magnitude of market generation charges and understated the TOU differentials. As a result, consumers would not see accurate price signals during peak periods and conservation would not be encouraged. IPPSA/SPPA submitted that the Electric Utilities Act, R.S.A. 1995, c.E-5.5 (the EU Act) requires that the DAT should be based on the pool price forecast for the period in which the DAT is to be in place. According to section 31.6(3)(b) of the EU Act:

(3) The direct access tariff must include

(b) a forecast of pool price to be paid by Alberta Power Limited or TransAlta Utilities Corporation, as the case may be, to exchange electric energy through the power pool for direct access customers for different hours of the day during the period in which the tariff is to be in effect, …

IPPSA/SPPA submitted that TransAlta should use a 1999/2000 pool price forecast to develop market generation charges, including TOU differentials. Market generation costs could be determined by applying the 1999 pool price forecast to the 1997 test year demand patterns. The “stranded cost/residual value” (SC/RV) component of costs could then be derived as a residual.



By using a 1999 pool price forecast, market generation price signals would reflect incremental costs while the overall revenue requirement would be met. IPCAA

IPCAA submitted that the COSS was flawed since costs and allocation factors used in the study were out of date. Use of 1996 costs and load data was inappropriate since costs and load data had changed since 1996. At minimum the 1998 Negotiated Settlement changes should not have been included in the analysis. The 1998 changes included a reduction in reservation payments. IPCAA accepted that major changes were still in progress and could not have been incorporated within the COSS. Examples of such changes were the Power Pool Request for Proposals and the filing of Distribution Tariffs. TransCanada

TransCanada commended TransAlta’s use of updated 1998 forecast information in order to calculate TOU differentials. However, TransCanada submitted that TransAlta’s approach to the COSS was questionable since it selectively and arbitrarily used adjustments to incorporate updated and more recent information into the study (such as adjusting revenue requirements to 1997 or using a price forecast for TOU differentials). In general TransAlta ignored major trends in costs since 1996 that should impact rates in1999–2000. Further, TransAlta was not totally willing to provide information for intervenors attempting to develop an alternative COSS. Consequently, intervenors were restricted in their attempts. The Board should give greater consideration to the COSS of either IPPSA/SPPA or IPCAA, each of which more closely reflect costs and appropriate rate designs for 1999 and 2000. Further, TransAlta should be directed to prepare future COSS and rate design schemes based on factors that are relevant to the period within which the rates will be in effect. FIRM Customers

The FIRM Customers proposed an alternative method to TransAlta’s method of adjusting the revenue requirement for the COSS from 1996 to 1997 levels. TransAlta prorated the costs in their entirety reducing the cost of all elements of the cost of service by 2.01%, since total costs declined 2.01% in 1997 relative to 1996. The FIRM Customers proposed pro-rating of 1996 costs to 1997 by function. The FIRM Customers argued that this method was theoretically more sound than TransAlta’s method of pro-rating costs as a whole. However, in supplemental testimony3 the FIRM Customers reconsidered and accepted that on a practical basis pro-rating by function was not an appropriate method. Such a procedure becomes problematic whenever loads are different than forecast or in cases when costs are substantially different by function. In particular, as a result of the legislated reallocation of 25 kV plant costs


3 Exhibit 68


from distribution to transmission, the FIRM Customers concluded that there was no preferable way of handling the pro-rating issue. Consequently, the FIRM Customers accepted TransAlta’s approach to the pro-rating. However, the FIRM Customers recommended that the Board should direct the use of pro-rating by function in future cases where costs are not shifting significantly between functions during the specific period. Board Findings

The Board recognizes that the COSS reflects forecasts of pool prices, energy, demand and number of customers. Those forecasts were examined in TransAlta’s 1996 Phase I proceeding and hence TransAlta has some justification for using them in the Application. However, the EU Act came into force in May 1995, setting the stage for gradual and significant restructuring of Alberta’s electric industry. As a result, the 1996 Phase I proceeding and the current Phase II proceeding take place in a period when the electric industry is in transition toward a competitive market. The restructuring in the electric industry has led to many changes, with potential changes yet to occur; the current period is truly unique and represents more of an exception rather than the norm. Consequently, the Board shares intervenors’ concerns that the magnitude of costs and their appropriate allocation among customer classes has changed substantially since 1996 and will continue to change. The Board sets out its view on how these changes should be dealt with in Section 3(a). The graph, on page 12, demonstrates the extent of the increases in the pool price since 1996. With respect to the significant increases in pool prices and changes in TOU differentials, the Board considers that pool price signals must be the basis for appropriate market responses. TransAlta provided a forecast for 1998 TOU that was prepared well before the end of 1998 and used the 1996 forecast for other classes. The Board considers that the actual 1998 pool price record would provide a more appropriate basis for forecasting the annual average cost of energy for 1999 fixed rate classes including the TOU classes. As a general principle the Board does not consider that there should be any premium over forecast costs in any rate the DISCO charges its customers. The risk that those costs may be higher or lower should be the DISCO’s risk, unless the customers agree to assume some of the risks or the Board determines a risk premium is appropriate. The risk to the DISCO of pool price variance from forecast on load exceeding the DISCO’s entitlements was considered as part of the DISCO’s risk in Decision U97065. Therefore, the Board is not persuaded that there should be any risk premium inherent in the DISCO’s TOU rates or for that matter any other fixed rate arising out of this proceeding. Therefore, the Board considers that the TOU energy charges should reflect the forecast pool price, without any premium, during the TOU period each charge is in effect.



The Board therefore directs TransAlta to use actual 1998 pool prices for the purpose of determining the cost of pool purchases used in the refiling. The actual 1998 pool price record should be utilized in the calculation of pool purchases, unit obligation values (UOV), TOU rates and annual average energy costs. (See also Section 3(b))

(b) Allocation of Costs Related to Generation

60Background

The transition to competition implicitly defined in the EU Act provides for the recovery of costs related to generation using three components: the pool price, the reservation price, and the UOV. The allocation of these generation-related components to distributors was prescribed in a way that attempted to ensure the DISCO ultimately paid the fixed plus variable costs of generation (paralleling the demand component and energy component of traditional regulation).4 The EU Act allows the possibility that the method of allocating these costs to end-use customers may differ from the method by which they were allocated to distributors. However, the allocation must include the legislated hedges: reservation payment (RP) and UOVs. 10

20

30

40

50

TransAlta proposed to allocate UOVs to end-use customers in a manner similar to that used to allocate entitlements to distributors in that it was based on forecast hourly energy use by customer class. Parties generally accepted that approach for TransAlta, but there were differences in their view of the details appropriate to the allocation.

-

Jan-9

6

Mar-96 6 -96

Sep-96

Nov-96 7 7 -97

Sep-97

Nov-97 8 8

l-98

Nov-98

Monthly Average Pool Price

.00

.00

.00

.00

.00

.00

May-9

Jul

Jan-9

Mar-97

May-9

Jul

Jan-9

Mar-98

May-9

Ju Sep-98

$/MWh

TransAlta proposed to use a method to allocate the RP to end-use customers that differed from the method used to allocate the RP to distributors. The Company proposed to allocate the reservation payment on a basis related to energy use.5 Specifically, the allocation of the RP would be based on the forecast UOV refund allocated to each customer class, and as noted above, the UOV allocation was to be based on forecast energy use.6 Some parties submitted that the allocation of the RP to customers should relate directly to the levels of demand associated with customer classes. The parties supporting a demand allocation approach generally advocated the 3 winter/9 non-winter months (3W/9NW) methodology that was accepted in Electric Energy Marketing Agency (EEMA) proceedings.

4 The RP approximately covers fixed costs. Pool Receipts minus the UOV yields variable generation costs (for sales up to the UOA). This is discussed in detail in the Phase 1 Decision U97065, and will not be dealt with in detail here.

5 Reservation payments had been allocated to distribution companies, under the EU Act, using the EEMA demand allocation.


6 The allocation, as proposed by TransAlta for fixed rate customers, would be done on an hourly basis for each customer class.


TransAlta’s Allocation Methods

In its 1996 COSS TransAlta classified all distribution costs related to generation, including legislated financial commitments, as energy costs. Generation costs were allocated based on the cost of acquiring the energy consumed by each customer rate class in each hour in which the costs are incurred. The energy was forecast at the 25 kV interface between transmission and distribution systems. The hourly cost of pool purchases, net of unserved energy, was allocated to each rate class based on its share of the total energy forecast to be purchased by the DISCO in the hour. Gas deferral account charges and power pool trading fees were allocated to each rate class in the same proportion as the net cost of pool purchases incurred by that class. The sum of obligation value refunds for all generating units in each hour was allocated to each rate class based on its share of the total energy forecast to be purchased by the DISCO in the hour less temporary energy. Reservation payments were allocated to each rate class in proportion to the obligation value allocated to that class. TransAlta indicated that allocating obligation value refunds and reservation payments on a similar basis would ensure each customer rate class receives an appropriate portion of existing generation’s fixed and variable costs of operation. TransAlta indicated that “as we move forward into the future, the Power Pool is really the commodity exchange for generation, and there is not necessarily any demand charges associated with energy consumption. To the extent that you are buying unhedged energy or purchasing energy from the spot market, there are no demands associated with it whatsoever, it is simply the energy charge for that hour.”7 Similar to other commodity markets, contracts should be viewed in the context of their relative cost to the spot market. Allocation on an hourly basis is more appropriate to Alberta’s new industry structure than allocation based on annual energy as in prior cost of service studies. Allocation by hourly energy gives the same result as allocation by hourly demand. Unlike the pre-1996 3W/9NW allocation method, the new allocation methods reflect the manner in which the DISCO currently incurs generation costs. Hence, the proposed allocations of generation costs were fair and reasonable. Further, the allocations made the urgently needed price signals (available through hourly pricing for generation) more visible. Based on these considerations and the inseparable nature of legislated financial commitments created by the EU Act, TransAlta’s contended that the energy based allocation of generation costs is appropriate for Alberta’s restructured electric utility industry.


7 Transcript, p.849


Position of the Intervenors

Parties Supporting TransAlta’s Allocation Method

FIRM Customers

The FIRM Customers supported TransAlta’s approach to allocating generation costs. The FIRM Customers submitted that TransAlta’s proposal was forward looking, reflected current cost causation, was consistent with market pricing of hedges and would create a smooth transition towards the new market structure. Section 38(1) of the EU Act refers to costs “not significantly different” for “entitled electric distribution systems.” It does not apply to cost allocations between customer classes or individual rates. The restructuring has resulted in many changes including a significant portion of DISCO transmission payments now being based on energy. There can be no guarantee of a “bumpless” cost allocation to customer classes. Following three years of “bumpless” restructuring, the Board should consider new goals and alternatives in customer rate design to support the creation of a new, competitive market rather than duplicating the past. TransAlta’s generation allocation reflects the costs and recognizes the flatter loads that are being experienced. TransAlta’s approach provides hedges at the same price per kilowatt-hour hedged for all customers. Under the approach interruptible customers are not subsidized since former Class 3 interruptible customers’ current loads are included for allocation purposes and the interruptible credit is charged separately to the FIRM Customers. The backward looking 3W/9NW demand allocation method proposed by other parties should be rejected. The FIRM Customers submitted that the pre-1996 3W/9NW demand allocation method was not valid for allocation of RP and UOV since it does not reflect current market conditions. Unlike TransAlta’s method, the demand method does not recognize the value of a hedge to the customer. The UOV can be viewed as providing a hedge against the pool price to the customer, with the value of the hedge related to the energy hedged and the difference between the hedged and unhedged price. This value should be reflected in the price paid for the hedge by the customer. The cost of the hedge is the RP, representing the fixed costs paid to obtain the hedged energy. TransAlta’s proposal was consistent with market pricing, since kilowatt-hours are to be hedged at the same per unit price for all customers and value is aligned with cost. In contrast the 3W/9NW allocation method would result in high load factor customers paying less to hedge a certain amount of energy than lower load factor customers. It would be unsustainable for one group of customers to pay the same amount for a hedge as an alternative group of customers, but be allowed to hedge twice as much energy. The industrial approach is only sustainable under regulation and represents a barrier to the development of a true competitive market. Similarly under the SC/RV method, the residual value benefits from the embedded system would be disproportionately allocated to high load factor classes. It is not



logical that the FIRM Customers low load factor customers who have disproportionately paid for the system’s fixed costs should not realize its benefits in a significant manner. The 3W/9NW allocation method was no longer appropriate due to the high load factor of the Alberta system, the relatively even monthly peaks and the spread of unreliability (as represented by high pool prices) into many periods across the year. The 3W/9NW demand no longer reflects the cost structure of the Alberta generation system since there is no significant “load valley” created by the Alberta winter peak. For the 12 months from September 1997 to August 1998 the average difference in on-peak loads between the three winter and nine non-winter months was only 8% or 554 MW. The only remaining “load valley” was in April and May. In the New World when generation capacity is short, power pool prices reach high levels and the data provided by Mr. Marcus demonstrated that high pool prices can occur throughout the year, not predominantly in winter months and not just at the peak hour of the month. Power shortages and capacity cost incurrence are no longer coincident with monthly peak loads and occur over large numbers of peak hours over the year. Even without restructuring, this analysis supports a shift towards a broader measure of capacity cost allocation. TransAlta’s allocation of RP in proportion to UOV ensures a higher allocation of RP to all high pool price hours. Such allocation better reflects prevailing flatter load conditions. However, submitted the FIRM Customers, if the Board approves allocation of RP using a demand-based allocator, then UOVs should also be allocated using the same demand-based allocator. This would effectively allocate the same number of hedged kilowatt-hours per kilowatt to each customer, resulting in a more market-oriented hedge. On-peak energy use (the GSS allocator) should be the demand allocator, since it is a better measure of the need for capacity on the Alberta system. The 3W/9NW demand allocator no longer represents the current distribution of unreliability across the Alberta Interconnected Electric System. In addition, over 400 MW of Class 3 customer demand should be included in the demand to be allocated. Whereas IPCAA stated that interruptible loads should not be added back, the FIRM Customers submitted that Class 3 interruptible loads must be in the demand used for the purpose of cost allocation. Otherwise two industrial groups would effectively collect interruptible costs twice – once through exclusion from the demand for cost allocation and a second time by including a specific schedule in the cost study to collect interruptible rate credits from the FIRM Customers. The IPCAA and IPPSA/SPPA methods inappropriately excluded over 400 MW of interruptible load from the demand used in cost allocation, resulting in a subsidy to industrial customers in the tens of millions of dollars. Parties Opposing TransAlta’s Allocation Method

IPCAA, TransCanada and IPPSA/SPPA were concerned that TransAlta departed from the demand intensive approach to generation cost allocation by adopting an energy intensive



method. Under TransAlta’s allocation of generation supply costs on an energy basis there would be little difference in total per kWh generation cost between classes. This was very different from the past even though the nature of overall Provincial generation costs had not significantly changed since restructuring and legislated hedges were established to preserve this reality at the DISCO level. The parties supported methods that essentially tied the allocation of the RP to the levels of demand associated with customer classes and advocated the 3W/9NW demand allocation accepted in recent EEMA proceedings. A summary of each party’s position follows. IPCAA

IPCAA agreed with TransAlta that generation costs should be allocated in the way in which they were incurred. The point of contention was what “causes” RP. TransAlta’s “energy only” allocation of legislated hedge costs ignored the underlying fundamentals on which the hedges were designed. The manner in which DISCOs pay for generation costs from existing plants had not changed in nature. The DISCOs variable cost was equivalent to energy purchases at pool prices less UOV refunds. Fixed costs were represented by the RP. To the extent that the overall make-up of costs had remained unchanged, it was reasonable to allocate the fixed costs and variable costs in keeping with the past. The way the DISCO has incurred these costs was a result of the way the reservation price and the legislated hedges were designed and that’s what should be taken into account in doing the Phase II cost study. Legislated hedges were designed to carry the cost structure of existing, regulated generation into the New World of electricity restructuring wherein other generation costs can be guided by the market. TransAlta’s new method ignored how generation and transmission costs were incurred by the DISCO. Since the nature of fixed costs and variable costs have remained unchanged it was logical to continue to allocate RP using the 3W/9NW demands. The way DISCOs pay for costs from existing generation has not changed in nature. IPCAA’s detailed analysis indicated that DISCO RP shares were within roughly 10% of generation 3W/9NW demand shares. The 10% difference was a result of setting the DISCO RP shares to maintain each DISCO’s total generation and transmission costs as they would have been under EEMA. The original allocation of RP shares was based on 3W/9NW with the “bumplessness” adjustment. The RP shares were reset based on the same principle in 1997 to offset transmission cost reallocation among DISCOs due to the Transmission Administrator (TA) rate design. IPCAA submitted that, if there is a cost-causative method to allocate the RP among customer classes, it would be based on maintaining total generation and transmission costs for each class as they would have been under EEMA. The share of RP allocated to the DISCOs is fixed so changes in usage by customers will not influence the shares. TransAlta does not incur RP on the basis of hourly energy usage. Hence, it would be inappropriate to allocate RP in terms of hourly price signals.



TransAlta’s COSS significantly changed the method of allocating generation and transmission costs from that used in the past. Significant inter-class revenue shifts resulted from TransAlta’s COSS. The proposed reallocation of revenue responsibility was attractive to customer classes such as the Small General Service class, but unattractive or biased against the Irrigation, Large General Service-Large and Wholesale classes. If allocation of generation costs was not on an energy-only basis, Large Industrial Rates (6200-6400) would be receiving rate reductions in the current proceeding, rather than the rate increases TransAlta proposed. IPCAA submitted that legislated hedges were designed to accomplish a specific purpose, and not to reflect commercial terms as the FIRM Customers suggested. Otherwise there would have been no need to create them by a piece of legislation. Mr. Marcus acknowledged in cross-examination that there was not an established market for hedges, nor would there be one in the foreseeable future. As a result of the concentrated market for the supply of electricity and the potential for the exercise of market power by customers, Mr. Marcus concluded that electricity as a commodity may not have a relatively stable price trend, thereby restricting the potential for a competitive market. IPCAA submitted there was no basis to view hedges on a market basis. The FIRM Customers’ submission that the old 3W/9NW approach would have changed even without restructuring ignores both the past and the future. Mr. Drazen indicated that legislated hedges were designed to be in place during the period extending from surplus generation to load/resource balance. Load/resource balance appears to be occurring during the 1998–1999 period. Thus, the hedges were designed to coexist with changing supply/demand conditions in the electricity market. As a result of new generation coming on stream, the supply/demand balance will continue to change in the future. The “fixed-variable” methodology being advocated by IPPSA and Alberta Power Limited (now ATCO Electric or AE) is similar to the “bumpless” method supported by IPCAA. The difference between the two viewpoints is that the “bumpless” methodology takes into account the need to adjust the allocation of generation costs to offset the shift of transmission costs from 100% demand-related to partly on-peak energy related. IPPSA/SPPA

IPPSA/SPPA submitted that legislated hedges represented a measurement of “stranded costs/residual value” (SC/RV). SC/RV was equal to the RP less the UOV credit. The SC/RV represented the difference between the costs that the utilities would be allowed under regulation and the costs that they can potentially recover in the market. No causal basis exists in the restructured world for allocating SC/RV since it is not caused by any identifiable characteristics of demand or customers. Instead allocation and rate design for SC/RV should rely on fairness, value of service and historical considerations.



Various jurisdictions in the U.S. are pursuing similar restructuring wherein customer classes are being asked to continue to carry the costs allocated to them when restructuring commenced. Similarly in Alberta, equity and consistency suggested that SC/RV should be allocated such that total generation costs for each class approximated cost allocation results from the pre-restructuring fixed-variable scheme. Each class’ SC/RV would then be the difference between allocated generation costs under the previous EEMA method and the market generation costs allocated each class using hourly 1999/2000 forecast pool prices. TransAlta did not present any arguments in terms of cost causation, historical precedent or market information explaining why RP costs should be assigned on the same basis as UOVs. Nor had TransAlta provided a significant rebuttal to the proposals of IPPSA/SPPA and IPCAA. TransAlta did not present any generation planning studies, long-term demand forecasts or any other evidence that would suggest that there should even be a change in traditional generation cost allocation methods. Thus, TransAlta could not argue that the cost framework for regulated generation had changed as a result of industry restructuring. The traditional concept of classifying generation costs into “demand” and “energy” components was not truly representative of the restructured world. For example, under an hourly “energy” allocation scheme, low load factor classes that consume proportionately more energy during peak periods are allocated higher average per-unit costs than high load factor classes. Hourly energy charges effectively include both an energy and a demand component since pool prices are positively correlated with hourly load. This relationship should be reflected in market generation tariff charges. TransAlta’s allocation methodology would result in constant energy charges for generation across customer classes. Constant energy charges would result in high load factor customers subsidizing low load factor customers. That would reduce the incentive to improve the customer load factor for industrial loads. The FIRM Customers’ argument that the 3W/9NW method was no longer appropriate was irrelevant since allocation of generation costs under regulation depended on generation planning which no longer existed. Costs to be allocated were related to plants built under the EEMA regime and the objective must be to assign costs incurred as a result of past planning assumptions. It was logical to continue to utilize a historical cost allocation method consistent with the allocation of historical costs. Further, in the absence of the new regulation scheme, there was a very low probability that the Board would approve allocation similar to TransAlta’s proposal. The FIRM Customers’ proposal that legislated hedges be treated like commercial hedges ignored the “bumpless” spirit of the new electric utility regulation. Further, it was illogical to use costs that were determined by legislated fiat as a proxy for a market commercial hedge.



In response to TransAlta’s assertion that Mr. Knecht’s proposal would keep the allocation of generation costs the same as it was under EEMA, regardless of changes in the pool price, IPPSA/SPPA noted that there was no pool price mechanism during the EEMA regime. Further, most of TransAlta’s generation costs were the same as they were under EEMA and any changes in pool prices were virtually offset by changes in the UOV. Those historical regulated costs should be viewed in the context of the historical regulatory regime. TransCanada

TransCanada noted that faced with the same legislative framework and the “bumpless” provision, AE has not altered its approach to generation costs, and continued to support the 3W/9NW method. TransCanada submitted that there was a need for consistency between TransAlta and AE in the treatment of generation related costs. TransCanada submitted that an embedded COSS needed to reflect cost causation and TransAlta had abandoned that need. TransAlta should not materially change its method of allocation of generation costs unless it could furnish proof that the nature of costs had significantly changed. TransCanada disagreed with TransAlta that there was a significant change in the nature of generation costs in comparison to functionalization under earlier legislation.8 TransCanada referred to Board Decision U97065, page 31, which states that the legislated hedge structure will ensure that existing generation will be provided at its fixed plus variable costs of operations. Since this outcome is very similar to the result in the Old World, prior to 1996, the nature of fixed costs and variable costs have not changed in the New World. TransCanada emphasized that the RP is related to the recovery of those fixed costs related to generating plants added to rate base prior to 1996. In prior Board Decisions, the Board has repeatedly considered and approved the modified fixed variable method, with the result that fixed costs have been classified as being demand related and have been allocated based on demand in prior cost of service studies. In contrast, TransAlta’s argument appears to be that UOVs are energy related, UOVs and RP are part of legislated financial commitments and as a result RP should also be classified as energy. TransAlta had not adequately proven that costs of regulated generation up to the UOAs should be classified as energy costs. The legislated inclusion of UOVs in the recovery of fixed and variable costs provides no pertinent information on allocation of other components (including RP) of that recovery. There was no evidence that legislation had ruled out the fixed cost components of regulated generation or that new competitive generated power had displaced the fixed cost characteristics of existing generation cost structure. Further, there would be no inconsistency in allocating reservation payments on a demand basis and introducing hourly price signals through the pool price. The FIRM Customers’ argument that the need for generating capacity, as measured by high pool prices, no longer occurs primarily in the winter months was made on one year of non-normalized


8 TransAlta Cost of Service evidence, page 2


data and that year was a mild “El Nino” weather year. Further, the FIRM Customers’ assumption was that unreliability is directly related to high pool prices, but to the extent that pool prices may be influenced by market power and units down for maintenance, they are only rough indicators of generating capacity. TransCanada submitted that 81% of Class 3 interruptible loads was not considered firm for the purpose of determining RPs (representing 100% less 19% of Class 3 loads that were considered firm in the calculations establishing RPs). The FIRM Customers’ proposal that 100% of Class 3 interruptible load be used for cost allocation in 1996 was inconsistent with prior Board decisions. Position of TransAlta

TransAlta submitted that recommendations for the 3W/9NW method to continue being used were flawed. There was no evidence presented that the 3W/9NW allocation represented the current reality with respect to the way DISCO costs are presently caused. Further, the recommendations were based on the invalid assumption that the manner in which generation costs were allocated to the distribution system for the purpose of determining their legislated shares of total regulated generation, will necessarily reflect how those costs are currently caused. TransAlta was not abandoning cost causation since it was logical to allocate costs to rate classes on the basis that those costs are incurred by the DISCO, instead of applying the method used in the determination of RP shares to DISCOs The recommendations were also inconsistent with the acknowledged need to provide accurate price signals to customers. IPCAA cannot advocate keeping costs the same while promoting the need for more accurate price signals. Cost causation needs to be determined within the context and period in which it is occurring in order to establish accurate price signals. TransAlta’s proposal would achieve that goal. In response to arguments that it was wrong to delink the allocation to customers from the allocation among distribution functions, TransAlta argued that, considering IPCAA’s position in past proceedings, IPCAA appeared to be only concerned about delinking when it indicated a greater cost allocation to the large industrial rate class. IPCAA was in favour of delinking when the result was lower cost allocation to the industrial class. In regard to a “bumpless” transition, TransAlta noted that Section 38 of the EU Act was not intended to deal with the costs allocated to end-use customers. Market reforms would be constrained if industry were to strictly adhere to “bumplessness” at the end-user level. Further, IPCAA had not provided any evidence to substantiate the claim that other jurisdictions were unbundling without interclass cost reallocations. Mr. Drazen admitted that many different cost allocation methods, including hourly energy, existed in other jurisdictions.



TransAlta noted that while IPPSA/SPPA confirmed that allocation of SC/RV represents the major issue, the IPPSA/SPPA concluded that total generation costs should be allocated using the pre-restructuring fixed-variable scheme, even though the SC/RV issue was assumed to be the key issue. IPPSA/SPPA’s method of allocating generation costs was disconnected from market signals such as the pool price. A generation cost allocation scheme that has no causal basis is flawed and ultimately represents a futile exercise. Board Findings

The parties directed much of their attention to the question of how and why the allocation of the RP and the UOV to distributors was done in the way that it was, and whether or not the allocation to end-use customers should mirror that approach. The Board found this discussion useful but after considerable reflection on the objectives of restructuring, the Board has concluded that a forward-looking approach to allocation is more appropriate. In particular, the Board has attempted to identify the desired end result of restructuring and places considerable weight on making specific decisions that would assist in achieving that result. The Board’s rationale in adopting an energy-based allocation approach includes the considerations set out below.

• In evaluating the view of some parties that the Board should emphasize a “bumpless” transition, the Board reviewed its position taken in Phase I, Decision U97065. The conclusion in Phase I was that the EU Act assigned responsibility for that issue to the legislature and left the Board free to emphasize other principles. That conclusion is reaffirmed here.

The Board considers that its Decision should reflect efficient cost causation and encourage economic decision-making by customers to the greatest extent possible subject to the provisions of the EU Act. . . . . In allocating costs among functions, the Board will continue to have regard to factors that reflect efficient cost causation and encourage economic decision-making. The Board also considers that the cost allocations it may ultimately approve in the design of customer rates are not constrained by any bumpless principle.9

• The EU Act established legislative hedges to ensure the low embedded costs of existing

generation were passed on to customers during the transition to a competitive environment. The resulting framework was necessarily somewhat distorted in allocating fixed and variable costs to distributors because of steps taken to minimize the potential “bump” in overall generation and transmission costs and preserve each DISCO’s costs as they would have been under EEMA. Over time, since the framework was put in place,


9 Decision U97065 Pages 76-77, 31 October 1997


the distortion has increased.10 Therefore, the relation to cost-causation is increasingly tenuous, and the Board is concerned that allocating costs to customers under some adaptation of this historical framework, which would likely require significant assumptions and compromises, could result in an unfair allocation.

• Restructuring has altered the nature of the benefits that flow to customers. For example,

the new system provides a less reliable expectation that power will always be available. Previously the system ensured, through a planned minimum surplus, that there was always adequate supply to handle the foreseeable level of demand. In future, the availability of power will depend on the efficient functioning of the market. The achievement of balance in supply and demand, in the short term, may require some response by customers to high prices to bring the market into equilibrium through reducing quantities demanded.11 Since customers no longer get the specific benefits associated with planned reserve capacity normally sufficient to meet peak demands, there is no justification for allocating costs related to that capacity as is done through a differential demand charge. As well, there is no longer a guarantee that power will be provided at approximately the embedded costs of generation. The market determined price will increasingly dominate the actual cost of power to consumers, and, at least in the short term, the market price may exceed the embedded costs of generation.

• The province is in the third year of its five-year transition from regulated generation to

competitive generation. As the transition has proceeded, the relevance of demand-based cost allocation methods has declined.12 In a competitive market, all costs are variable in the long term and demand-based allocation would be inappropriate. The only costs incurred for generation will be reflected in the pool price. In fact, continuing to use a demand-based approach to allocation might involve a degree of unfairness to some customers.

• The method of allocating costs of generation through the RP, and the associated UOV,

should not conflict with the operation of the power pool as a competitive market. That means the method of allocation should not interfere with the pool price signal being passed through to customers. This implies that the method should not allow the allocation of the UOV to vary with pool prices. Ensuring that the pool price signal is the essential cost of energy seen by customers will help ensure that market prices work to provide

10 The increase is attributable to the changes in transmission cost allocation and DISCO loads relative to

the forecasts used in the initial allocation. 11 In the long term, imbalance, even potential imbalance, in the market will provide an incentive for the

development of new sources of supply.


12 To the extent entitlements exceed load, there is more support for allocating them according to historical allocation methods. However, as demand has grown in the province, the use of entitlements has increased until each DISCO’s load will exceed its entitlements in most hours. The benefits of existing low-cost generation are now essentially fully used by customers. Therefore, new load will affect DISCO costs in the same way regardless of class and arguments related to historical cost-causation have less force.


maximum incentives for efficient behavior on both the supply and demand sides of the market. The method of allocating costs should also fairly allocate the hedges among existing and new customers. Discrimination against new customers is not consistent with competitive markets, historically accepted criteria of fairness, or with one of the key purposes of the EU Act of 1996.13 Similarly, discrimination or differentiation in pricing based on load factor is no longer appropriate since load factor does not affect the generation costs incurred by the DISCO to serve incremental load.

In brief, the desired end result of restructuring is a competitive market for selected electrical services . There are at least two implications important to this decision, relating to generation costs, that follow from that:

• First, historical approaches to allocating generation costs (to either DISCOs or end-use customers) will not be relevant once a competitive market is fully developed. At that time, costs will have to be recovered through market prices. In the short term, some energy may be sold at prices that do not cover all costs. But in the long term such an anomaly cannot continue. Generators who cannot cover their costs through market prices will exit from the market.14

• Second, there should be no difference in the price charged any customer for a kWh

purchased from the pool by the DISCO in a given hour. The transition from the Old World has advanced to the point where the Board believes demand-based allocation of generation costs is no longer appropriate. There is a need at this time to align the emerging system with the requirements of a competitive marketplace. That requires that both RP and UOV be allocated based on energy use and in a manner that ensures they do not diminish the strength of the connection between market-determined prices and customer behaviour. The pool price will be the implicit basis of allocation when a functioning market is fully developed. The Board believes it would enhance the transition to accept that reality and implement a parallel approach now. That is another reason why the Board is not willing to accept the demand-based approach proposed by IPCAA and IPPSA/SPPA, which would inevitably postpone the time at which players must directly engage the market. However, the Board does not fully support the method of allocation that was proposed by TransAlta either. Although TransAlta’s approach of allocating on an energy basis does more

13 The EU Act section 6(a)(i) reads as follows: “The purposes of this Act are (a) to establish a framework

that replaces the Electric Energy Marketing Act so that averaging of generation costs is phased out as regulated generating units are removed from regulated service and new arrangements are made so that (i) the benefits of and responsibilities for costs associated with electricity produced by regulated generating units are shared by all consumers of electricity in Alberta, and,…”


14 This is the theoretical result of competitive markets but is somewhat unlikely in the current circumstances. If it were to happen, the generating units involved could continue to operate since new owners would be likely to purchase them at a significant discount, in effect reducing their cost to the system.


closely approximate a market result, the method introduces a distortion to the price signal by linking the allocation of RP to the allocation of the UOV. The distortion occurs because the UOV is higher during periods of high prices, leading to a higher allocation of RP to high pool price hours.15 In consequence, the variation in the net hourly energy cost seen by a customer would differ from the variation in the pool price (as illustrated in Appendix 4). The signal that should be seen by customers is the pool price. Only pool price signals will generate the appropriate market response, since they alone reflect the relation of demand and supply that exists in the market during any given period. Moreover, under TransAlta’s method of allocating the UOV refund, customers forecast to use energy in a particular hour of the year would get the benefit of the called entitlements available to reduce the net cost of energy in that hour. For those customers, the result would be to reduce the effective pool price in that hour. Such a result was appropriate at the DISCO level, given the initial objective to ensure power was priced at its embedded costs. However, for purposes of moving toward a competitive market, the Board believes it is not appropriate to effectively hold the net price the customer sees at the level of the UOP. This is particularly relevant for actual pool price DAT customers, who are intended to be exposed to the full variation of the pool price. Therefore, the Board considers the annual forecast UOV refund should be treated as a benefit that is spread equally across forecast annual DISCO energy use. That will ensure that the benefit related to existing low-cost generation is equitably shared by customers while also allowing customers to be exposed to the full pool price variation (see Appendix 5). Similarly, the Board considers that the variation of the pool price signal will not be distorted if the RP is spread equally across forecast annual DISCO energy use. Therefore, in the COSS the Board considers that the cost allocated to customer classes for each kWh should be the hourly pool price adjusted by a constant factor “H”, which captures the net amount of the legislated hedges for each kilowatt hour of energy use. H is defined as the net amount calculated by deducting the annual total UOV from the annual total reservation payment and dividing the result by annual energy use. The resulting allocation can be summarized as follows: Cost allocation/kWh = cost of energy purchased from the pool + H, Where H = forecast annual DISCO RP – forecast annual total of DISCO UOV refunds Forecast DISCO total annual energy use

H is the same constant amount for all customer classes. This approach to allocation will cause variation in the hourly total generation cost to match the variation in pool price for all customer classes, thereby ensuring that the pool price signal will


15 The Board acknowledges the concerns raised by intervenors regarding the potential for the exercise of market power. While the Board does not necessarily accept that market power has been exercised, it views the prevention of that result in future as being the responsibility of the Power Pool. It would not be efficient to address that possibility through the allocation process under discussion here.


begin to influence customer energy use. For rate design purposes, pass through of the pool price the DISCO faces may be on a forecast basis for fixed rate customers or on an actual basis for pool price flow-through customers. For fixed rate customers, consumption will not be affected in the short term by the actual hourly pool price. Changes in their patterns of use will occur gradually. However, variable rate DAT customers will clearly see, and be able to respond to, the variation in the actual hourly pool price. The Board considers that the H factor will provide the fair allocation, required by the EU Act, of the value and cost of the legislated hedges among all future users of electric energy in Alberta. The demand based allocation methods would have given some customer classes a greater share of, or right to the net benefits of the legislated hedges, even though the DISCOs incur the same cost, the pool price, for incremental energy to serve customers in any class. The DISCO should allocate the same cost for each kWh of energy to be consumed by a customer in an hour regardless of the customer’s rate class. There should no longer be any demand based charges in the generation component of the rate. The charges in each rate to pass through the average cost of energy purchased from the pool and allocated costs of the legislated hedges should be as follows:

• For fixed rate classes the separate charges per kWh would be H and the forecast class annual average pool price.

• For actual pool price DAT classes (see Section 4(a)(13)) the separate charges per

kWh would be H and the actual hourly pool price.

• For TOU classes the separate charges per kWh would be H and the forecast average annual pool price in each TOU period (presumably a different value for each TOU period).

Each class’s annual average cost of energy and the DISCO H component should be separated in each applicable rate schedule. Ideally the rates would reflect a tested forecast for the year they are in effect. For fixed rate classes, forecast hourly load profiles developed from the hourly total energy forecast, load research data and load growth statistics would provide hourly energy usage characteristics for each customer rate class. Then hourly pool price forecasts and hourly load profiles would be used to determine each fixed rate class’s annual average cost of energy. Similarly, the H component would reflect current forecast annual DISCO RP, forecast total DISCO annual UOV refund and forecast DISCO annual energy use. The Board sets out how the cost of energy and the H component will be determined for the rates arising out of this Decision in the Rate Design Section 3(b).



(1) Unserved Energy

Unserved energy represents the curtailment of interruptible load in the generation models used to forecast energy production. Unserved energy can come from interruptible load and from temporary energy. After establishing dollar amounts for unserved energy, TransAlta allocated unserved energy based on a forecast of energy consumed by hour by rate class. In the proceeding, a concern was raised whether TransAlta should have instead allocated unserved energy related to individual class loads in proportion to the forecast energy purchases for the rate classes in which those loads reside. In relation to this issue, IPCAA submitted that an alternative approach would have been to separate forecast energy purchases from the Power Pool by rate class in order to allocate unserved energy across the customer classes. Position of TransAlta

As directed by the Board in Decision U97065, TransAlta credited the value of unserved energy against the distribution utility’s purchases of energy at the pool price. TransAlta confirmed that unserved energy represents the curtailment of interruptible load in the generation models used to forecast energy production. As a result of model limitations, TransAlta did not model interruptible loads as energy that can be subtracted from the provincial load. Instead, TransAlta modeled interruptible loads as “phantom generating units” that are called to “operate” (or ultimately drop off the system) during times when all available generating units and imports are not sufficient to support the provincial load. In its response to Information Request CCA.TAU-5, TransAlta explained the methodology and allocation for the cost of unserved energy. TransAlta’s energy production model treated interruptible loads as “phantom generating units” that operated when the pool price reached $30/MWh for Class 2 interruptible loads and $40/MWh for Class 3 interruptible loads. This approach resulted in a curtailment of load during hours when the price was forecast to exceed $30/MWh. As a result of modeling unserved energy, TransAlta calculated the unserved energy credit to total $2.761 million for 1996. In order to allocate the unserved energy credit, TransAlta calculated the amount of curtailment of pool prices in each hour that price was forecast to exceed $30/MWh, together with the amount of energy purchased for each customer rate class for that hour. The hourly unserved energy credits were then added up for each rate class to determine the class’s total unserved energy credit. TransAlta responded to IPCAA’s recommendation regarding the allocation of unserved energy relating to Class 2 and Class 3 loads. TransAlta submitted that, as directed by the Board in Decision U97065, the value of unserved energy was credited against the distribution utility’s purchases of energy at the pool price. Consistent with this methodology, the impact of pool price flows through to all rate classes since energy is purchased from the Power Pool on behalf of all rate classes. TransAlta stated that the costs and credits for unserved energy were included in its Cost of Service Adjustments for Temporary Energy and Interruptible Credits, documented in



Table Rates A-3.1 in the Phase II filing. Since TransAlta followed the Board direction, it recommended that IPCAA’s recommendation should be rejected. In its final argument, IPCAA submitted that TransAlta acknowledged that the unserved energy credit was allocated to all forecast load, and was not allocated separately to Class 2, Class 3 and firm loads. Based on this acknowledgement, IPCAA recommended that the unserved energy relating to Class 2 and Class 3 loads should be allocated in proportion to the forecast energy purchased for the rate classes in which those loads reside. For example, Class 3 unserved energy should be allocated to the forecast energy purchases that serve Class 3 load. Board Findings

In Decision U97065,16 the Board agreed with the Utilities’ method of crediting the value of the unserved energy against the DISCOs’ purchases of energy at the pool price and directed that this procedure also be used in the refiling. The Board accepts TransAlta’s method and allocation approach for the cost of unserved energy. The Board agrees with TransAlta’s view that energy purchased from the Power Pool represents energy purchased for all rate classes, and does not represent purchases made on behalf of specific rate classes. Thus, TransAlta’s allocation of the unserved energy credit represents an appropriate method, in which all customer classes receive a portion of the credit. (2) Trading Fees

In its COSS, TransAlta submitted that power pool costs included power pool trading fees incurred by the distribution owner. Similarly to pool purchases, TransAlta classified trading fee costs as energy costs. With respect to allocation, TransAlta allocated power pool trading fees to customer rate classes in the same proportion as the net cost of pool purchases incurred by each rate class. Intervenors did not present any evidence or arguments regarding trading fees during the proceeding. Board Findings

The Board accepts TransAlta’s classification of power pool trading fees as energy costs and allocation of trading fees to rate classes in proportion to the net cost of pool purchases for each rate class. (c) Allocation of TA Billings

The TA Billings charged the DISCO by the TA17 must be allocated to customers. Customers expressed concerns with the way that the Grid Interconnection Services (GIS) and the Grid

16 Board Findings on Interruptible Load, Page 107


17 See Rate Design – Criteria, page 50 for further clarification


Standard Service (GSS) charges were allocated. The TA’s GIS charge recovers the cost of system support services and the cost of the local portion of the transmission system required to meet the NCP demand of the local area load. The TA’s GSS charges recover the bulk portion of the transmission system required to meet the coincident peak of the local area loads. TransAlta proposed to recover the costs of the TA Billings and the distribution costs through a single “Delivery Service Charge.” (1) Grid Interconnection Services

TransAlta’s Delivery Service Charge was structured to include recovery of the cost of the TA’s GIS billings. TransAlta stated that the GIS charges were allocated to each customer rate class based on that class’s estimated share of total GIS demand. The total GIS demand, contracted with the TA for interconnection capacity, was based on forecast peak load at each point of delivery. The forecast peak included demand to allow for switching and load growth, thereby reflecting a balance between the cost of additional interconnection capacity and the excess demand charges that would be incurred if interconnection capacity were exceeded. TransAlta explained that an individual rate class’s contribution to demand at each transmission point of delivery was not known. TransAlta estimated that each rate class’s share of the total GIS demand was based on the customer load characteristics and the NCP of the respective rate class. TransAlta stated that no GIS demand was allocated to the Temporary Energy rate class as TransAlta had not contracted with the TA for any GIS demand to provide Temporary Energy service. Intervenors expressed concern that the customer or customer class causing the system demand to increase were not necessarily the same customer or customer class bearing the prorated costs associated with the increase in demand. TransAlta’s Cost of Service Study initially allocated these additional costs based on the percentage of the difference between the sum of the individual customer peak loads for each customer class less the NCP of the same customer class. TransAlta refined its allocation method to incorporate the demand of individual customers served at 69 kV or higher and filed the revision as Exhibit 37. TransAlta stated the refinement also addressed IPCAA’s concern that, “If a point of delivery serves a single customer, the TA charges can be explicitly identified.”18 IPCAA agreed. Position of the Intervenors

The FIRM Customers stated that TransAlta originally allocated GIS costs to customer classes using NCP loads. However, when the GIS demand exceeded the sum of the class NCP load,


18 Evidence of Drazen Consulting Group, p.16


TransAlta allocated each class the same percentage of the difference between class NCP and the sum of individual customer peaks. The FIRM Customers contended that TransAlta’s refined approach was deficient for three reasons. First, the GIS demand for customers served at transmission voltage (69 kV or above) was the customer NCP for those customers. Second, the FIRM Customers identified two smaller customer subgroups whose GIS demands were approximated by customer NCP, namely, wholesale customers and partial customers. The FIRM Customers identified the wholesale customers as having a load representing a large fraction of the substation serving them and partial customers as having loads that were erratic and large relative to the size of their substations and thus would set the GIS demand level when backup power was taken. Third, The FIRM Customers stated that, for small customers, the customer NCP has little to do with the GIS demand. The FIRM Customers submitted that the diversity between class NCP and customer NCP was close, but the GIS demand differed from class NCP because of seasonal differences in load across the utility’s service area affecting substation loading. The FIRM Customers contended that using customer NCP demand as part of the allocation method for smaller customers was not reasonable. The FIRM Customers submitted that TransAlta should break the province down into industrial substations, where one or more industrial customers constitute over 80% of load, and winter and summer peaking stations. The FIRM Customers suggested that TransAlta make calculations of NCP load by class for those different types of facilities and that the customer NCP for smaller customers should not be used. AIPA submitted that farm and irrigation class NCP demands should be combined for the allocation of TA Billings. AIPA disagreed with TransAlta’s suggestion that combining the annual NCP for farm and irrigation services was not appropriate because of differences in location, size, and usage between farm and irrigation services. AIPA agreed that not all parts of TransAlta’s franchise area had irrigation service, but submitted that most irrigation services were located on farms in the southern part of the province. AIPA submitted that size differences between farm and irrigation services at the customer level would be diminished at the feeder and substation levels. AIPA also suggested that differences in usage patterns between farm and irrigation services should reduce the allocation of TA Billings to the classes by offsetting peak winter usage for farms against the peak summer usage of irrigation. Although not recommending combining the farm and irrigation service customer class NCPs for this proceeding, AIPA agreed with FIRM Customers that a combined approach should be investigated in a future proceeding.



Position of TransAlta

With respect to the FIRM Customers’ claim that wholesale customers’ load represented a large fraction of the substation serving them, TransAlta submitted that the proposed allocation of GIS demand treated the demands of the wholesale service customers appropriately. TransAlta referred to Table COS A-3.3 Rev 1 (2 November 1998) and stated that the GIS demand of 20.1 MW for wholesale service customers was slightly (two per cent) less than their customer NCP of 20.5 MW. TransAlta submitted that the GIS demand reflected that wholesale service customers’ loads were strongly coincident with the peak load at the substations serving them. TransAlta also submitted that the FIRM Customers’ claim that partial requirement service customers had loads that were erratic and large relative to the size of the substations serving them was not supported by the evidence and should be rejected. The data in Table AIPA.TAU-8(g).4, indicated that although the peak demands from partial requirement service customers may vary, their peak demands tended to be non-coincidental with other rate classes’ use of the electric system. With respect to the third deficiency suggested by the FIRM Customers, TransAlta responded that substation load was the sum of customer loads served through the substation and seasonal differences across a service area accounted for customer loads at substations being greater than the rate class NCP. TransAlta submitted that differences between customer loads and rate class NCP were accounted for by TransAlta’s allocation of GIS demand. TransAlta challenged AIPA’s position that farm and irrigation rate class NCP demands should be combined for the allocation of transmission costs. TransAlta submitted that since irrigation services were typically larger and more expensive than farm services such that their costs differed and that because each has different load characteristics, the two classes should remain separate. TransAlta also submitted that the diversity of the usage pattern between farm and irrigation services provided the basis for a separation of these classes and all other rate classes, rather than, as AIPA had suggested, the basis for combining the NCPs of farm and irrigation services. TransAlta indicated that AIPA did not provide the rationale to support combining the farm and irrigation service NCPs and that TransAlta’s allocation of transmission costs remained appropriate. Board Findings

The Board notes that, the GIS portion of the Delivery Service Charge is designed to recover the TA’s GIS billings allocated to customers on a basis of contract demand measured by reference to the NCP at each point of delivery. The TA Billings to TransAlta include charges for the local transmission capacity contracted to serve each point of delivery and any excess demand charges incurred for demand exceeding that contracted.



In Decision U97065, the Board stated, at page 624, that the TA’s GIS rate should be structured to recover the costs of the local portion of the transmission system required to meet the NCP demand of the local area load, without regard to the overall system coincidence. The Board considers that the NCP method is appropriate. TransAlta has used the NCP method to allocate total forecast GIS demand charges to customers and customer rate classes. The customer load characteristics for services at 69 kV and higher are used as the class NCP for determining the GIS demand to address IPCAA’s concerns that if a point of delivery serves a single customer, then transmission charges can be explicitly determined and should be directly passed through to that customer. Additional cost allocations for switching and growth would then be unnecessary for such customers. The Board also considers that pass through of customer specific TA Billings will help ensure that more accurate unbundled costs to serve customers arise out of this proceeding and the Distribution Tariff proceeding. However, since in Section 2(c)(3), the Board finds that 25 kV costs should now be in transmission, the Board directs TransAlta to also pass through the actual TA Billings to every customer served at 25 kV or higher who is the only customer at a point of delivery. The Board has some concerns respecting the method of forecasting excess GIS billings when the contracted demand is exceeded at points of delivery. TransAlta’s approach results in an additional per kW charge on all customer demand to recover the GIS billings. As a general principle the Board does not consider that there should be any premium over forecast costs in any rate the DISCO charges its customers. However, the Board does not consider that the concern must be specifically addressed, since in Section 3(b) the Board directed TransAlta to use its actual 1998 TA invoiced kWh and kW and actual customer and class NCP and usage to determine its kWh and kW charges relating to TA Billings in the refiling. Under the method the Board directed, a forecast of excess billings is not required to ensure appropriate allocation of TA Billings to customers and classes. The Board is not persuaded that combining the NCPs of farm and irrigation services for purposes of allocating TA Billings is appropriate for this decision. Therefore, the Board accepts TransAlta’s allocation based on separate farm and irrigation classes. However, the Board considers that there may be some merit in AIPA’s concerns. Therefore, the Board directs TransAlta to investigate combining the NCP demand for farm and irrigation service classes for the purpose of allocating TA Billings and provide the study at the preliminary distribution tariff proceeding. (2) Grid Standard Services

TransAlta’s Delivery Service Charge was structured to include recovery of the cost of the TA’s GSS billings. TransAlta’s rate consisted of charges for both the energy forecast to be transferred



and energy losses forecast to be incurred, similar to the TA’s GSS rate. TransAlta allocated the TA’s GSS charges recognizing that these costs were related to system energy requirements. TransAlta classified GSS charges as energy costs and allocated these costs to the rate classes proportionately to their forecast energy consumption during the on-peak and off-peak periods defined by the TA. On-peak transfer charges were allocated to each customer class based on that class’s energy transfer during on-peak hours. TransAlta’s GSS transmission loss charges were allocated to each customer class based on that class’s on-peak and off-peak energy transfer and the transmission losses charge during on- and off-peak hours. IPCAA submitted that transmission costs should be allocated to customer classes according to the 3W/9NW methodology used prior to 1996. Position of the Intervenors

IPCAA presented a comparison of the Old World to the New World for allocating transmission costs. IPCAA concluded, based on assumptions about the level of TA costs and rate design, that the Old World method, of 3W/9NW, resulted in a similar, although not identical, allocation of charges. IPCAA stated that the TA’s rate design for GSS recovered a majority of the total transmission costs through energy charges so, if customers were to reduce their usage, the GSS charges would be automatically reduced. The FIRM Customers objected to IPCAA proposing an ad hoc change to reverse the change to transmission cost causation resulting from restructuring. The FIRM Customers indicated that TransAlta’s GSS charge for energy transfer and transmission losses were allocated on an energy basis. The FIRM Customers noted the Board had established this basis for use in later years through Decision U97065. The FIRM Customers, in the absence of any persuasive evidence, submitted that ignoring the future cost allocation and returning to the past methodology was inappropriate. The FIRM Customers submitted that any delay in implementing changes resulting from the industry restructuring created inequities and possible future rate shock. The FIRM Customers contended that IPCAA’s proposal to maintain the 3W/9NW method confused the continuity in the COSS with the continuity of a rate design criterion which moderated rate changes resulting from changes in cost allocations. The FIRM Customers identified an error in the load factor used to allocate the costs to the irrigation rate class but noted the error was corrected in TransAlta’s revision dated 23 October 1998.



Board Findings

The Board agrees with TransAlta that costs associated with transfer of energy and transmission losses should be allocated according to the energy requirements and usage periods of its customers and rate classes. The Board considers that the pre-1996 allocation method is no longer relevant to the current industry structure. The Board considers that allocating transfer charges based on on-peak and off-peak energy results in a fair allocation. Similarly, allocating transmission losses using on-peak and off-peak hours results in a fair allocation to TransAlta’s customer classes. However, in Section 2(c)(1) the Board directed TransAlta to pass through the actual TA billings to every customer served at 25 kV or higher who is the only customer at a point of delivery. In Section 3(b), the Board directed TransAlta to use its actual 1998 TA invoiced kWh and kW and actual customer and class NCP and usage to determine its kWh and kW charges relating to TA Billings in the refiling. (3) TransAlta 25 kV Plant

Some Intervenors objected to TransAlta including the costs of the 25 kV plant as part of the distribution function rather than the transmission function as specified by the EU Act as amended in March 1998. Position of TransAlta

TransAlta indicated compliance with Directive G10 of the Board’s 1996 Phase I Decision U97065, wherein the Board directed TransAlta to reclassify the costs from transmission to distribution for the 25 kV equipment within transmission substations. TransAlta stated that the decision governed the manner in which 1996 costs were to be functionalized. TransAlta submitted that any requests to reflect amendments to the EU Act, which arose on a going-forward basis in 1998, were beyond the scope of this Application. TransAlta submitted evidence, in Exhibit 15 and updated in Exhibit 47, which indicated the difference in costs allocated to each customer rate class if the 25 kV plant was reclassified from distribution to transmission. Position of the Intervenors

TransCanada submitted that the treatment of 25 kV reclassified facilities should be deferred to the tariff proceeding of the TA. TransCanada indicated that 25 kV facilities were not just an issue between transmission and distribution functions, but also an issue between rate classes. As well, TransCanada suggested that TransAlta had to second guess how the TA would incorporate these costs into the transmission rates. TransCanada suggested that, during the TA’s proceeding, the parties would have an opportunity to review the costs and the rate mechanism to charge for the reclassified facilities.



The FIRM Customers submitted TransAlta’s position put form over substance and ignored the legislation. The FIRM Customers stated that the new definition of “transmission facility” in s.1(3) of the Electric Utilities Amendment Act (EUA Act) amended 30 March 1998, applied to tariffs “that have effect in and after 1998.” The FIRM Customers stated that TransAlta requested the rates in effect by April 1999 and the rates should be based on legislation currently in force as it affects the definition of cost. The FIRM Customers suggested that failing to consider the impact of the existing legislation thwarted the legislative intent. The FIRM Customers submitted that the legislation reclassifying 25 kV facilities back to transmission is more appropriate than information allocating 25 kV property to distribution. Board Findings

The Board, in Decision U97065, directed the Utilities to identify the 25 kV facilities between the low-voltage terminals of the step down transformer and the substation fence and to reclassify the costs of these facilities from transmission to distribution. The Board, in Part 1 – General, Section 5(c) of Decision U97065 further directed the Utilities to reclassify the 25 kV facilities to the distribution function for 1996 refiling purposes. The Board notes TransAlta has designed customer rates using a COSS based on the 1996 Board approved revenue requirement. However, the Board notes that section 2(b) of the EUA Act amends, for purposes of tariffs that have effect in and after 1998, the definition in subsection (1)(dd) to the extent that subclause (v):

includes all equipment in a substation that is used to transmit electric energy (a) from the low voltage terminal referred to in subsection (1)(dd), and (b) to the electric distribution system lines that exit the substation and are

energized at 25,000 volts or less. The Board considers that the applicable legislation takes precedence over Decision U97065 for rates effective in 1999. The Board, therefore, finds that 25 kV facilities should be classified as transmission costs. In Exhibit 47 TransAlta provided the cost of service based on certain assumptions after the inclusion of 25 kV costs in transmission. However, in Section 3(b) of this Decision the Board directed TransAlta to prorate the 1996 distribution cost allocations (as adjusted for the removal of the 25 kV costs from distribution) in the Application to the 1998 residual in the refiling to determine the levels for the DISCO Services components in the refiled rates. The Board recognizes that removal of these costs from the distribution function, means these costs must be recovered by the TA’s rates. The Board notes that TransCanada suggested that TransAlta must second guess how the TA would incorporate the additional transmission costs into the transmission rates.



However, in Section 3(b) the Board directed TransAlta to update its 1996 forecast transmission costs using the TA’s interim 1999 rates which are adjusted for the effect of reallocating the 25 kV plant to transmission. Therefore, the Board considers that TransAlta’s per kWh and kW charges to recover TA Billings will be appropriately adjusted for the effect of reallocating the 25 kV plant to transmission. (d) Allocation of Distribution Costs

(1) Distribution Property

TransAlta identified an error in the 1992 COSS which resulted in town property not being assigned to the General Service customer class for the allocation of distribution costs in 1992. In the 1996 COSS, TransAlta corrected the error and allocated town property to the General Service customer. IPCAA objected to the correction and IPPSA/SPPA and CCA suggested that the allocation of distribution costs to customer rate classes needed additional study. Position of Intervenors

IPCAA

IPCAA indicated that TransAlta had changed its allocation of distribution cost three times during the course of the proceeding, suggesting that the problem of out-of-date information was acute inasmuch as some records were not updated since 1992. IPCAA stated that TransAlta’s proposal increased the allocation of town property to General Service and Large General TOU rate classes by $59.9 million from a nil balance allocated in 1992. IPCAA submitted that TransAlta’s explanation that the basis for past practices could not be identified was unacceptable. IPCAA submitted that changes to the allocation was inappropriate and recommended TransAlta be required to continue to allocate distribution town property using the method employed in the 1992 COSS until evidence is provided to change the allocation. IPPSA/SPPA

IPPSA/SPPA expressed concern regarding the process of eliciting cost of service information during the proceeding. IPPSA/SPPA submitted that the lack of detailed working papers precipitated the need for a thorough review of significant data underlying the assumptions in the COSS. Specifically, IPPSA/SPPA recommended that TransAlta prepare a detailed study of the allocation of gross distribution plant. As part of the study, IPPSA/SPPA stated that TransAlta Decision U99035 Page 35 10 August 1999


should demonstrate that the distribution assets categorized as oilfield plant were not used to serve any other customer rate class. IPPSA/SPPA requested that the study include working papers, backup data, and any studies relied on for the allocation of costs and that this information form part of the next Phase II filing. CCA

The CCA calculated that $119,006 or 8.8% of miscellaneous distribution property was assigned to the residential customer rate class with little justification. The CCA stated that TransAlta used a “minimum system method” conducted in 1990 wherein all distribution property that could not be directly assigned was allocated 2/3 on demand related property and 1/3 on number of customers. The CCA submitted that residential customers were, therefore, assigned the bulk of customer related costs. The CCA submitted that the minimum system method of allocation was neither an appropriate tool for cost causative factors nor was 1990 information valid for 1996. The CCA submitted that the miscellaneous district property included common facilities that were installed to provide service to more than one customer rate class. The CCA suggested that, to the extent that the minimum system method assigned one third of the demand related costs to customers, the result assumed that the costs of common facilities varied with the number of customers. The CCA stated that common facilities were not required to put in place a minimum system to serve customers. Therefore, the CCA concluded the minimum system method to assign cost responsibility for assets that have nothing to do with a minimum size distribution system was illogical. The CCA recommended that TransAlta prepare a miscellaneous distribution property allocation based on a more recent study to determine cost causation and file this study at its next GRA. Position of TransAlta

TransAlta contested IPCAA’s position by stating it was inappropriate to continue a practice identified as being erroneous simply because the cause of the error had not been identified. TransAlta noted that IPPSA/SPPA acknowledged that it was not possible to determine if plant assigned to oilfield property was used to serve other loads nor was it possible to determine if property, other than that assigned to oilfield, was used to serve oilfield. TransAlta submitted that the categorization of property included in the 1996 COSS should be accepted as the appropriate basis for the allocation of those components of TransAlta’s distribution costs which vary with distribution system property. TransAlta suggested that the CCA was misinformed and explained that two-thirds of distribution property was classified as demand-related and one-third was classified as customer-related. The demand-related was assigned based on coincident peak demand of the customer rate class while the customer-related was assigned based on number of customers.



TransAlta directed the CCA to an information response wherein the minimum system method was used to determine the percentage of distribution property required to serve customers at minimal load conditions and the balance of distribution property was identified as demand-related. TransAlta disputed the CCA’s claim that using the minimum system method was illogical. TransAlta explained that common facilities would include a minimum system component to provide service to those customers. In addition, TransAlta suggested that the CCA did not provide evidence to show how the design of distribution systems had changed since 1990 nor how those changes would affect the results of a study of the minimum system method. Board Findings

The Board agrees with IPPSA/SPPA that more detail may be necessary to demonstrate that the allocations properly reflect the cost causation. Therefore, the Board directs TransAlta to provide information relied upon and relevant to determining the allocation of the town property to the customer rate classes at the time of its next Phase II GRA. The Board is not convinced that a minimum system method from 1990 is necessarily out of date or inappropriate for determining cost causative factors. However, the Board directs TransAlta to update the study on the minimum system method as part of the information supplied to substantiate the allocation of town property. The Board encourages refinements and enhancements that result in more appropriate allocations. The Board agrees with TransAlta that a misallocation in previous studies should be corrected. Therefore the Board accepts TransAlta’s allocation of town property. (2) Customer Contributions

Customer contributions were based on the contributions to TransAlta’s construction program forecast to be received from customers in each customer rate class. TransCanada suggested that these contributions were not recorded by customer rate class but rather by service level. TransCanada

TransCanada stated that TransAlta did not track customer contributions by either transmission or distribution functions. TransCanada suggested that half the contributions received were “unmatched” and that this portion was allocated in proportion to the matched contributions. TransCanada submitted that an inequity was being created between rate classes because TransAlta had not been keeping track of customer contributions by rate class but rather by service level. TransCanada recommended, in view of the unbundling between transmission and distribution functions that TransAlta identify and track customer contributions by those functions and record the contributions by rate class rather then by the “Rate by Service Level.” Decision U99035 Page 37 10 August 1999



TransAlta suggested that TransCanada had misinterpreted the record when TransCanada stated that half the contributions were unmatched and that these unmatched contributions were allocated in proportion to matched contributions. TransAlta explained that matched contributions referred to customer contribution records that correlated to customer account information allowing assignment of contributions to particular rate classes. TransAlta further explained that unmatched contributions could not be matched with a specific service or correlated to customer account information. However, TransAlta indicated that, where possible, unmatched contributions were assigned to rate classes based on indicators such as the name of the contributor. If an assignment was still not possible, unmatched contributions in each service level were allocated to rate classes in proportion to the matched contributions in the service level. Board Findings

While the Board is not persuaded that TransAlta has misallocated the unmatched portion of customer contributions, the Board considers that the concerns expressed by TransCanada with respect to TransAlta’s record keeping may be warranted. The Board is also concerned with the high percentage of customer contributions not matched to specific accounts. However, with no other methodology proposed, the Board accepts TransAlta’s method of assignment and allocation for this proceeding. As a result of the separation of the integrated utility’s costs by function in the restructured industry, the Board considers that contributions should be recorded by the function for each customer rate class. The Board directs TransAlta to record future customer contributions by the function for which the contribution is received as well as by rate class. (3) Other Distribution Operating and Maintenance Expense

TransAlta allocated other distribution expenses to each customer class in proportion to that class’s share of the distribution property. The CCA objected to the allocation citing that some expenses were not related to distribution property and should be allocated using distribution costs. CCA

The CCA suggested that certain expenses included in the Other Distribution Operating and Maintenance (O&M) Expense such as wages, staff and office expenses were not related to distribution property. The CCA submitted that TransAlta had not provided enough details to arrive at the conclusion that all the items included in this expense total were driven by distribution property. The CCA suggested that some of the cost elements would be more appropriately allocated using the distribution cost subtotal. The CCA submitted that a detailed



analysis of the items included in Other Distribution O&M Expense should be provided at the next GRA. Position of TransAlta

TransAlta explained that wages, staff expenses and office expenses within this expense category were related to the operation and maintenance of distribution property and included activities related to operations and maintenance of “distribution substations, overhead and underground distribution lines, meters, customer installations, streetlights and other distribution facilities.” TransAlta asserted that these facilities were comprised of distribution property confirming distribution property as the correct allocator. Board Findings

The Board is not persuaded that any costs included in the other distribution O&M expense category should be allocated on a different basis than proposed by TransAlta. The Board considers expenses included in this account to be reasonably allocated based on the class’s share of the distribution property. Accordingly, the Board accepts the expenses included in this account and approves TransAlta’s method of allocating other distribution O&M expense using distribution property as the base. (4) Marketing and Sales

Marketing and sales expenses were comprised of energy efficiency program costs and other marketing and sales expenses. Energy and efficiency program costs were assigned directly to those customer rate classes in which the programs were offered. The remaining costs were allocated to customer rate classes in proportion to each class’s subtotal of all distribution costs excluding marketing and sales, general and administration expense and revenue offsets. IPPSA/SPPA proposed replacing TransAlta’s allocation method with a 50% demand and a 50% customer-related allocator. The FIRM Customers rejected the IPPSA/SPPA proposal. The CCA also rejected the IPPSA/SPPA proposal and objected to TransAlta’s method of allocation. IPPSA/SPPA

IPPSA/SPPA suggested that marketing costs were “piggybacked” on top of distribution costs. IPPSA/SPPA stated that TransAlta’s cost assignment assumed that, because oilfield customers had a higher customer contribution level and higher linear tax levels and because they were more rural, oilfield customers should bear a disproportionate share of marketing costs. IPPSA/SPPA suggested that marketing costs for oilfield customers may be relatively small, since many oilfield accounts can be served by meeting the needs of a relatively small number of corporate customers. IPPSA/SPPA suggested that the best method for assigning marketing and sales costs would be to study the individual components and directly assign as many as possible. IPPSA/SPPA



recommended that, even though TransAlta had taken a step towards direct assignment with the energy efficiency program costs, in the absence of a detailed study, TransAlta should adopt a 50% demand, 50% customer-related allocator for assigning other marketing costs. FIRM Customers

The FIRM Customers suggested the 50%/50% method proposed by IPPSA/SPPA was unfair to small customers and failed to recognize the high marketing sales activities required for oilfield customers. The FIRM Customers submitted that the arbitrary method proposed by IPPSA/SPPA did not bear any relationship even to a study carried out by ATCO Electric Ltd. (AE) in its1994 Phase II application. The FIRM Customers recommended that IPPSA/SPPA’s method be rejected and TransAlta conduct a specific analysis of marketing costs at the time of the next rate design proceeding. CCA

The CCA, in addition to agreeing with the FIRM Customers that IPPSA/SPPA’s allocation should be rejected, noted inherent problems with TransAlta’s method. The CCA suggested TransAlta’s method assumed that marketing expenses were driven by the asset related costs of depreciation, income taxes and return constituting about 70% of the total distribution costs. The CCA inferred a dubious connection of assets to such expenses as wages, staff expenses, office expenses, promotions, R&D and customer support. The CCA submitted TransAlta had also expressed doubt as to this connection during the proceedings. The CCA further questioned TransAlta’s dismissal of the distribution cost subtotal as unsuitable for Other Distribution O&M Expenses because of inherent asset related costs, yet, in the allocator for marketing and sales expenses, asset related costs were considered suitable. The CCA recommended that TransAlta conduct a specific analysis of items included in Other Marketing and Sales expense. Position of TransAlta

TransAlta stated that IPPSA/SPPA had not reviewed the marketing costs assigned to oilfield customers for any other utility nor were they aware that AE had conducted an analysis of marketing, operating and maintenance costs on each specific account in AE’s 1994 Phase II proceeding. TransAlta submitted there was little support for IPPSA/SPPA’s recommendation and it should therefore be rejected. TransAlta suggested that neither the CCA nor the FIRM Customers had provided evidence indicating TransAlta’s allocation was inappropriate. TransAlta noted that individual components of the activities covered in marketing and sales expense would vary class by class and it would be inappropriate to allocate them at such a detailed level. TransAlta suggested it was better, more effective and provided more continuity to use an allocator that was appropriate to the items included in the activity. Decision U99035 Page 40 10 August 1999


TransAlta stated that the allocation was reviewed in detail and found to be appropriate in the last Phase II proceeding. TransAlta submitted that repeating detailed reviews in the absence of evidence that underlying costs or premises had changed were duplicative, inefficient and should be rejected. Board Findings

The Board agrees with the FIRM Customers that the method proposed by IPPSA/SPPA is arbitrary and does not provide a more accurate allocation of marketing and sales expenses than the allocation provided by TransAlta. Accordingly, the Board rejects the 50% demand, 50% customer-related allocator proposed by IPPSA/SPPA for assigning marketing and sales expenses. The Board is not persuaded that the method used by TransAlta is unsuitable for allocating marketing and sales expenses. The Board agrees with TransAlta that evidence was not submitted to warrant a detailed review of the allocation method. Accordingly, the Board accepts TransAlta’s method of allocating marketing and sales expense using the subtotal of all distribution costs excluding marketing and sales, general and administration expense and revenue offsets. (5) Customer Accounting

TransAlta allocated the customer accounting expense to each customer rate class 95% in proportion to that class’s share of weighted customers and 5% in proportion to its share of revenue. The number of customers in each customer rate class was weighted based on billing and meter reading frequency. The FIRM Customers objected to the arbitrary classification of 95% customer and 5% revenue for allocating customer costs. FIRM Customers

The FIRM Customers noted that TransAlta allocated 61% of costs attributable to credit and collections, uncollectible accounts and contracts and orders based on weighted customers. The FIRM Customers submitted that TransAlta agreed more effort was required to deal with larger accounts. The FIRM Customers also submitted that TransAlta acknowledged that some bills were more complex and time consuming to issue yet 23% of the billing costs were based on billing frequency. The FIRM Customers recommended TransAlta reflect a true cost causation by conducting a minimum bill analysis. The FIRM Customers suggested this analysis include any direct assignment of costs, where possible, and demonstrate support for the 95% customer and 5% revenue allocation.




TransAlta suggested that the FIRM Customers had not provided evidence indicating TransAlta’s allocation was inappropriate. TransAlta stated that the allocation was reviewed in detail and found to be appropriate in the last Phase II proceeding. TransAlta submitted that repeating detailed reviews in the absence of evidence that underlying costs or premises had changed were duplicative, inefficient and should be rejected. Board Findings

The Board is not persuaded that the method used by TransAlta for allocating customer accounting expenses violates the principle of cost causation. The Board agrees with TransAlta that no evidence was submitted to warrant a detailed review of the allocation method. Accordingly, the Board accepts TransAlta’s method of allocating customer accounting costs.



3. RATE DESIGN

(a) Rate Design – Criteria

(a)


TransAlta indicated that its objective was to create fair, competitive, consistent and flexible rates which would satisfy all customer classes and appropriately reflect costs. TransAlta applied the following rate design criteria:

• realize the collection of TransAlta’s total revenue requirement, the required change in revenue and the allocation of that change to each customer classes;

• recognize the cost of service, reflecting a fully distributed cost analysis as well as the cost of facilities required to provide service;

• encourage the optimum use of supply facilities and efficient utilization of energy by promoting desirable load characteristics and discouraging undesirable load characteristics;

• recognize the value of service, giving consideration to the nature and level of competition and the degree of price sensitivity in each rate class;

• avoid undue discrimination between customer classes and individual customers within each class;

• acknowledge the history of the rates, including trends in the levels of charges and the stability of the rates;

• acknowledge rate structure and Terms and Conditions of Electric Service which provides for simplicity of understanding, acceptance by customers, ease of administration and economy of billing; and

• give consideration to the rates and practices of other utilities having similar types of load and service characteristics.

TransAlta stated that it met with customers and intervenor groups to obtain input regarding TransAlta’s proposed rates and potential timing of the Application. In the meetings, the customer and intervenor groups gave support to the unbundling of rates and the elimination of cross-subsidization as much as possible. TransAlta also held a series of information sessions for customers and intervenor groups prior to the Phase II hearing in order to familiarize the stakeholders with the Application. With respect to the timing of the change in the generation allocation method, TransAlta submitted that the 1996 COSS was timely since artificial restrictions on the cost of service would prevent meaningful comparison of revenues to costs. While the reality of post-1996 cost


3. RATE DESIGN TRANSALTA 1996—Phase II

causation has been reflected, it has not been created at the expense of rate stability. TransAlta also stated that the impact on rates resulting from its COSS had been mitigated through its implementation of a fair rate design. As an example, the utility allowed the revenue-to-cost ratios for each rate class to move approximately halfway to unity. In the design of its rates, TransAlta considered both the level and the structure of its individual rates. With respect to the Phase II filing, TransAlta gave consideration to the following rate design issues and concerns:

• the unbundling of rates into separate generation and delivery charges; • the apportionment of demand, energy and customer charges for each unbundled

component; • the number of demand, energy and TOU blocks; and • the level of interconnection capacity and minimums.

In terms of rate design procedure, the first step that TransAlta took was to assess the appropriateness of the level of each rate. Expected revenues under existing rates were compared to the total revenue requirement and to the costs attributed to each rate class. As a result, an initial percentage change was determined for each rate class. The rate design criteria were then applied to each rate. Based on the initial determination of rate levels, percentage changes were applied to existing rates to achieve the total revenue requirement. The next step was to focus on the structure of the individual rates. Changes to rate structure needed to also satisfy rate deign criteria. Having established the level and structure of rates, another determination of revenue yield was made and the entire process was repeated to achieve a balance across rate design criteria, while meeting the total revenue requirement. In keeping with the past, TransAlta designed the proposed rates such that the resulting revenue-to-cost ratios would be in the range of 95 to 105%. Ideally, TransAlta aimed toward a unity ratio (100%) in order to minimize cross-subsidization between rate classes. TransAlta proposed to unbundle its rates into two components: Generation Service Charges and Delivery Service Charges. In conjunction with this process, the COSS presents an allocation of TransAlta’s distribution costs combined with the cost of generation and transmission payments made to the generating companies and the TA. The Generation Service Charge was designed to recover all generation costs through energy charges. In comparison, the Delivery Service Charge was designed to recover the transmission and distribution costs. The Delivery Charge includes charges based on energy consumption and billing demand (peak demand). There is a demand component in the charge that has been designed to recover fixed costs of the local supply facilities. In contrast, the energy component was designed to recover the costs of the shared system. Similar to the Generation Service Charge, the energy component of the Delivery Service Charge is single blocked, blocked by demand or blocked by TOU. Decision U99035 Page 44 10 August 1999


TransAlta proposed to apply TOU energy charges in instances where customer meters provide sufficient data. Optional TOU rates will be provided to other customers whenever practical. TransAlta proposed that all services over 2,000 kW and new Oil and Gas Services should be billed on TOU rates, while such rates will be optional for Residential, Farm, Irrigation, Small General Service and General Service customers. TransAlta developed a new numbering system for its rates and options. Rate codes were logically organized and expanded from three to four digits to allow for flexibility and future changes. In its final argument, TransAlta confirmed that it had moved the revenue-to-cost ratios approximately halfway to unity for most rate classes. With respect to the Irrigation rate class, TransAlta increased rates by 10% in absolute terms, with the result that the revenue-to-cost ratio for this class would rise from 61% to 71% under the proposed rate (although the revenue-to-cost ratio increased from 64% to 75% in the 6 November 1998 refiling, representing a percentage increase of 17%). In summary, TransAlta submitted that its proposed rate class revenue-to-cost ratios were just and reasonable. TransAlta did not propose further unbundling of the Delivery Services Charge in the current Phase II filing since the principles related to distribution access service have not been developed. TransAlta submitted that it has instead proposed further unbundling of the Delivery Services Charge in the recently filed Preliminary Distribution Tariff (PDT) application. As a result, TransAlta saw no further reason to unbundle rates in this proceeding. In its reply argument, TransAlta responded to IPCAA’s argument that the applicant has attempted to obscure individual cost components by proposing a less than fully unbundled rate structure. TransAlta reiterated that the PDT application represents the next logical step in the unbundling of rates. Full customer choice is scheduled by legislation for 1 January 2001. Furthermore, TransAlta argued that further unbundling in the Phase II proceeding without a thorough review of costs would not be beneficial to the consumer, and would instead confuse consumers. As a result, TransAlta stated that IPCAA’s proposal for further unbundling was premature, representing a diversion from the issue of bringing rates into line with costs. Position of the Intervenors

IPCAA

IPCAA submitted in its evidence that TransAlta’s proposed rates appear to obscure important information and as a result delay the inevitable transition toward effective retail competition for all rate classes. IPCAA stated that the proposed rate design would restrict the development of a functioning demand-side market, and ultimately contribute to potential increases in pool price and brownouts. IPCAA concluded that TransAlta should instead focus on redesigning the rates for the purpose of facilitating increased price-responsive load and dynamic competition.



IPCAA submitted that in 2001, the DISCO’s role will be to deliver energy to the customer, referred to as the “wires” function. With respect to generation supply, the DISCO’s role will be to flow through the pool prices to customers. Finally, the DISCO should flow through the charges and policies of the TA to the customer. As a result of the changes in the DISCO’s role, the criteria for DISCO rate design should in turn change. With respect to this critical point, IPCAA argued that TransAlta still has proposed rate design criteria that can potentially influence the use of generation supply facilities. IPCAA therefore concluded that TransAlta DISCO has maintained Old World integrated utility thinking by incorporating such criteria despite the change in the DISCO’s role to acting as a simple delivery business. IPCAA argued that DISCO rates should be established for each year, in keeping with the way TRANSCO rates are set annually. Ultimately, 1998 costs are the relevant ones for rates that are in effect in 1998, and likewise rates that will become effective in 1999 should reflect 1999 costs. In order to design rates that allow current year cost levels to be incorporated on a continuing basis, rates should be unbundled into components that reflect the underlying industry structure. TransAlta separated rates into two components, generation supply and delivery. In contrast, AE proposed to unbundle its rates into the three components: generation, transmission and distribution services. IPCAA noted TransAlta’s reluctance to completely unbundle its retail rates in the current proceeding, arguing that TransAlta has dodged the real question of why it has chosen not to fully unbundle its rates. In support of its argument, IPCAA stated that the EU Act contemplates further unbundling of distribution costs into wires and retailing in the future. Thus, TransAlta could have made consumers aware of these costs in order to promote the efficient use of facilities. To the extent that TransAlta chose not to provide such information, it has slowed down the processes of unbundling. In its final argument, IPCAA submitted that the most significant task to be accomplished during the current Phase II proceeding is rate unbundling, for the purpose of developing a competitive market that is open to all consumers. By obscuring individual cost components and not totally unbundling rates, TransAlta was keeping customers in the dark and not allowing them to make informed decisions. IPCAA further stated that TransAlta appeared to be reluctant to move any further than required by legislation with respect to the unbundling issue. Thus, the Board can promote the development of a competitive market by directing that unbundled information be made available to customers. IPCAA was critical of TransAlta’s statement that it bundled transmission and distribution together since delivery will remain a regulated function. IPCAA responded that this statement did not represent a logical argument. For example, regulation of TA rates did not imply that transmission costs should be bundled with distribution. In addition, IPCAA argued that TransAlta was not consistent in its own practice, since Rate 780 has effectively applied a flowthrough of TA charges to the customer with a separate charge for distribution. Since distribution will be separated into individual cost components, IPCAA recommended that the



Board direct TransAlta to unbundle rates into all functional components and to further unbundle distribution charges into individual wires and retailing charges. In its reply argument, IPCAA submitted that TransAlta over the course of the proceeding had changed the explanation for not unbundling the delivery service. Whereas TransAlta initially stated that delivery would remain a regulated function, later it contended that the principles of unbundling must be established before any action could be taken. In response, IPCAA argued that while the PDT proceeding will address the unbundling of delivery services, it is important to commence the process of unbundling as soon as possible in order to provide more cost information to customers. IPCAA therefore repeated its recommendation that TransAlta be directed to unbundle its rates into functional components and distribution charges into separate charges. IPPSA/SPPA

IPPSA/SPPA submitted that TransAlta should re-file its tariffs with separate tariff charges for market generation, legislated hedges, transmission and distribution. IPPSA/SPPA argued that unless customers receive accurate price signals, they will not be in a position to modify their consumption behavior. IPPSA/SPPA recommended that generation service charges be sub-divided into a market generation charge and a SC/RV charge. Further, the market generation charge should reflect pool prices and be differentiated by daily and seasonal time of use. The SC/RV charge should reflect the forecast reservation payment less UOV credit. Whereas TransAlta proposed to bundle transmission, distribution wires and customer-related services into a delivery charge, IPPSA/SPPA submitted that this level of unbundling was insufficient, particularly in a jurisdiction where transmission costs represent a significant portion of a customer’s bill. IPPSA/SPPA stated that customers should be able to analyze their bills in order to determine whether changes in their rates are the result of changes in transmission factors under the management of the TA or due to changes in distribution factors under the management of the DISCO. With respect to distribution costs, IPPSA/SPPA recommended separating the costs and rates into wire charges and retailing charges. In addition, contracts should be unbundled. IPPSA/SPPA argued that a lack of a statutory requirement to unbundle did not represent a credible reason to maintain almost fully bundled rates. In addition, IPPSA/SPPA did not accept TransAlta’s argument that further unbundling would be administratively costly, particularly since TransAlta anticipated unbundling transmission costs from distribution costs as early as 1996 during the discussions about potential alternatives to Option 12. Also, TransAlta did not provide any evidence that supported its claim of higher costs. Finally, with respect to unbundling generation costs, IPPSA/SPPA submitted that TransAlta had not presented any reasons why further unbundling would be problematic or not worthwhile. IPPSA/SPPA was of the view that



market generation costs should be unbundled from historical SC/RV in order to allow customers to see visible rates from alternative suppliers of electricity. In its reply argument, IPPSA/SPPA argued that TransAlta was stalling in terms of progressing with rate unbundling. IPPSA/SPPA submitted that AE was capable of unbundling rates. Also, TransAlta has proposed less unbundling in its PDT submission in comparison to the level of unbundling proposed by intervenors in the current Phase II proceeding and by AE in its filing. IPPSA/SPPA stated that TransAlta has not prepared its customers for retail competition. By maintaining bundled tariffs as long as possible, TransAlta will ultimately be the primary beneficiary since it will be improving its competitive position in the generation and customer service functions at the time when competition arrives. FIRM Customers

The FIRM Customers submitted in final argument that a principle objective in rate design should be the recognition of competitive issues. There are three areas where competitive issues have become relevant. The areas are wholesale rates, company farm/REA rates and irrigation rates. The discussion regarding the FIRM Customers’ views about these rates are more fully discussed in the separate rate sections. For the remaining rate classes not subject to competitive issues, the FIRM Customers proposed a significantly greater movement towards a 100% revenue-to-cost ratio than proposed by TransAlta for those classes outside of the 95%–105% band. In addition, the FIRM Customers proposed greater dollar movements toward unity, in comparison to TransAlta’s proposal, for those classes with a revenue-to-cost ratio between 95% and 105%. In its initial evidence, the FIRM Customers recommended moving nearly all classes closer to 100% on both a percentage basis and an absolute dollar basis relative to TransAlta’s recommendation. However, as a result of the corrections to distribution cost of service19 and the further changes reflecting the movement of substation costs back to transmission rates20, the FIRM Customers lowered the recommended movement toward unity on a percentage basis in its updated testimony. At the same time, the movement in absolute dollar terms was greater for some rate classes. The individual recommendations regarding the revenue-to-cost ratios for the various classes as presented in Mr. Marcus’ supplemental evidence21, is discussed in the separate rate sections. The FIRM Customers recommended that further movement towards 100% revenue to costs (with the exception of the irrigation class which has a target rate) be established in the 1999/2000 Phase II proceeding. As an alternative, if 1999/2000 rates are established on the basis of a rider relating to existing rates without a Phase II General Rate Application (GRA), the FIRM

19 Exhibit 15 20 Exhibit 16


21 Exhibit 68, Schedule 5B (revised)


Customers recommended an even greater movement towards unity in the present proceeding, in comparison to the revenue-to-cost ratios originally proposed by the FIRM Customers. The FIRM Customers responded to IPCAA’s concerns regarding the unbundling of distribution charges. The FIRM Customers submitted that the PDT should address the distinction between transmission wires, distribution wires and retail function costs and revenues. The FIRM Customers submitted that IPCAA’s approach to the matter was not appropriate and may be incorrectly assuming that all costs can be functionalized to the distribution function in the normal manner. Alternatively, the PDT proceeding can more effectively review and address the appropriate approach to unbundling the delivery charge. As a result, the FIRM Customers submitted that TransAlta appropriately handled the extent of unbundling that was required as of the time of the current Phase II proceeding. In its reply argument, the FIRM Customers further stated that directing TransAlta to further unbundle the delivery charges in the current proceeding would require a predetermination of the PDT based on a currently incomplete and insufficient record. Board Findings

The Board notes that distribution rates based on Old World generation cost allocation methods have been in effect for the first three years (1996–1998) of the five year transition to deregulation in 2001. Across-the-board rate riders were agreed to in the 1997 and 1998 Negotiated Settlements. The Board does not consider that it would be appropriate to revise those rates retroactively and accordingly will deem the interim rates in place from 1 January 1996 to 31 December 1998 to be final rates in this Decision. In this first Phase II Proceeding in the New World the Board must determine an appropriate form and level for customer rates during the remainder of the transition to fully competitive markets in 2001. As in the allocation of generation costs, the Board considers it important to look ahead in performing that role. A major objective of the EU Act is to separate the integrated utility’s costs by function as much as possible in order to provide distinct functional segments in a competitive world. As discussed in Decision U97065:

Section 48(1)(a) of the EU Act provides, in part, that an owner of an electric utility shall keep books, records and accounts in a manner that provides a reasonable understanding of the operation of the electric utility, including keeping track separately of the costs of regulated generating units, transmission facilities and electric distribution systems, as well as of common costs, in accordance with rules established by the Board.22


22 Part 1 – General, section 5(a) p.78 (Functionalization section)


In Decision U97065, the Board further directed the utilities:

…to develop a method of accounting for regulatory purposes that keeps track separately of the gross revenues and costs pertaining to the operation of the GENCO, TRANSCO and DISCO functions and to file these revenues and costs at the next GRA.23

Thus, the direction of the EU Act is very clear in regards to the separation of costs by function at the integrated utility level. The DISCO’s revenue requirement is the distribution function’s portion of the integrated utility’s costs. The DISCO’s revenue requirement must also be unbundled. TransAlta “functionalizes” the costs in its DISCO’s revenue requirement into generation, transmission and distribution. The Board considers that it would be clearer if the revenue requirement were unbundled by cost source since the source of the costs are not necessarily well described by those functional categories. The cost sources to be used in the refilings and rate unbundling are: Energy Supply (currently including the benefits of legislated hedges and later the balancing pool cost/benefit), TA Billings and DISCO Services. However, the Board considers that the separation of distribution costs by cost source is only the first step in the move towards customer choice in 2001. Customers supported functionalization of charges, cost reflective rates, and minimization of cross-subsidization. The Board agrees and notes that the new industry structure allows for competition in many areas commencing in 2001. The pass through of more realistic costs to customers will allow them to begin considering and responding to market conditions. The Board considers that the second step is to ensure each rate has a separate component charge representing any separable component cost which may be subject to competition for the DISCO or which customers might benefit from seeing. The third step is to ensure the component charges are equal to the component costs. The first step towards cost pass through is the unbundling of the DISCO’s costs by cost source. Moving the DISCO’s revenue-to-cost ratio to 100% for each cost source will also allow for easier adjustment of rate levels as required by any new DISCO cost levels arising out of the 1999/2000 Phase I, the TA’s rate proceeding and the distribution tariff proceeding. Therefore, the Board directs TransAlta to set its DISCO’s overall revenue-to-cost ratios to 100% for each cost source. The second step is to separate component charges within each rate to pass through each identifiable component cost within the cost sources. The cost sources are defined to contain the component costs as follows:

• Energy Supply costs include the cost of energy purchases from the pool, the legislated hedges, pool trading fees and commercial hedges;


23 Part 1 – General, section 5(a) p.81 (Functionalization section)


• TA Billings costs include the separable portions of the charges the DISCO pays the TA; and

• DISCO Services costs include separable costs related to the wires function, metering, customer accounting and customer services.

Separate cost of energy charges and legislated hedge values would help customers choose between the pool price, TOU rates, and other fixed price rates and also to assess market hedging possibilities. Cost reflective unbundled charges would help customers understand and minimize the transmission charges they cause the DISCO to incur from the TA. The third step is to move each component charge to a level equal to the component cost from which it arises. The Board considers that the cost components in Energy Supply and TA Billings may be unbundled and set to appropriate levels at the present time. Customers also indicated that they would like to see unbundled delivery charges to help them choose between connection at the distribution or transmission level and future customer choice options. However, the distribution tariff proceeding is the appropriate forum for setting component charges which reflect the level of the component costs of DISCO Services. The information is not required for retail customer choice until 2001 and more current component costs, including those approved in the 1999/2000 Phase I Decision, will be available for consideration in the distribution tariff proceeding. At any rate, use of 1996 distribution costs, or the residual or prorated distribution costs from the recent negotiated settlements, would not necessarily result in unbundled charges reflecting current DISCO Services component cost levels. Further, customer evaluation of the differences between connection at the distribution or transmission level may also be impacted by the TA’s rate redesign. Therefore, at this time the Board considers that the primary focus in the design of rates should be to provide cost reflective charges for the separable component costs of Energy Supply and TA Billings and to recover the DISCO’s total 1998 revenue requirement. This will require that the portion of revenue requirement attributed to DISCO Services be a residual. The revenue-to-cost ratios for total DISCO revenue from each cost source should also be set at 100%. Customers would then see rates which reflect current cost levels and, if a new cost level for any one cost source arises from a future proceeding, it may be efficiently incorporated into customer rates without the need to examine the other cost sources. Theoretically, rate stability, energy conservation, value of service, historical development, and customer acceptance concerns should not prevent either customers or future competitors from beginning and continuing to receive the accurate cost information they require to make market driven choices. Practically, the Board recognizes that rate stability concerns and shortcomings of record keeping systems may in specific instances require overall rate class revenue-to-cost ratios other than 100%. In those cases, to keep the signals from Energy Supply and TA Billings clear and since the DISCO Services component is a residual at any rate, the DISCO Services components should be adjusted as required. Decision U99035 Page 51 10 August 1999


To ensure some degree of rate stability in moving to accurate cost signals, the Board directs that in the refiling, the DISCO keep the overall increase in revenue arising 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 rate should be moved to exactly 100%, with the DISCO Services component (which is a residual) adjusted to ensure the overall increase in revenue is less than 10% for every rate class. The Board notes that individual customers may see more than a 10% increase if their usage characteristics warrant. In summary the Board directs TransAlta to design rates so that:

• the DISCO’s total charges related to Energy Supply, TA Billings and DISCO Services are unbundled, with the revenue-to-cost ratio for each set at 100%;

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

• the overall increase in revenue over that collected from existing rates is kept at less than 10% for every class, by adjusting as required the “residual” DISCO Services amount to be recovered from customer classes. (The Board notes that individual customers may see more than a 10% increase if their usage characteristics warrant.)

(b) Rate Levels for 1999

The Board considers that the most appropriate basis upon which to set 1999 rate levels for the Energy Supply and TA Billings cost sources would be tested 1999 forecasts broken down by component cost. Unfortunately, tested 1999 forecasts broken down by component costs are not available at this time. The negotiated settlements only provide the 1997 and 1998 total DISCO revenue requirements. The Board notes the rates arising out of this Decision will be subject to adjustment after the Board decides the 1999/2000 GTA. Accordingly the rates will be interim in nature. However, for the market to function as efficiently as possible in line with the findings above, the Board also considers that the charges reflecting 1999 Energy Supply costs and TA Billings in the rates should be as representative as possible of the 1999 component costs. The rates should also be easy to adjust for changes in TA rates. Customer response to pool price improves the efficiency of the market and the Board is particularly concerned that there should be no artificial incentives to keep customers on a single level fixed rate if they prefer actual pool price DAT or the TOU DAT rates. The Board considers that all relevant values24 should reflect the best forecasts available for 1999 for fixed rate customers who are eligible to take DAT rates. Then DAT customers who do respond to the pool


24 The annual average cost of energy for each class, the DISCO annual reservation payment, total annual UOV refund, H amount (see Section 2(b)) and total annual load.


price will more likely be better off than customers on fixed rates. DAT customers must be allowed to respond to the hourly variation in pool prices without being overcharged because of the difference between forecast and actual average pool price. With proper forecasts the DAT rates will provide a benefit on a forecast basis for customers who respond to the TOU rate (See Section 4(a)(13)). The Board notes that TransAlta used forecast 1996 load data to derive the forecast 1996 customer numbers, hourly class loads and billing determinants. Then TransAlta used the 1996 class data along with forecast 1996 hourly pool prices to calculate the 1996 sales and cost data and prorated that 1996 data to arrive at the revenue requirement in the 1997 Negotiated Settlement. The Board considers that the prorated 1997 levels of transmission and generation costs TransAlta proposes to incorporate in rates are not necessarily reflective of the current costs arising from the Energy Supply and TA Billings cost sources. Considering the increase in pool prices since 1996, the class annual average cost of energy and TransAlta “H” calculated from the 1996 data TransAlta used in the Application would be quite different than current levels. The Board considers that use of the Application’s out of date data would be inappropriate to determine charges for Energy Supply and TA Billings for rates to be effective in 1999. In the absence of tested 1999 forecast data broken down by component costs, the Board considers that the 1996 forecast hourly pool prices should be updated. The Board directs that TransAlta apply the actual 1998 hourly pool price record to TransAlta’s actual 1998 class load data in its refiling. The Board directs TransAlta to apply its actual metered class hourly load to the actual 1998 hourly pool price record to determine a more appropriate annual average cost of energy for each fixed rate class. Similarly, the Board directs TransAlta to use the average actual pool price in each TOU period in 1998 as the cost of energy components in the TOU rates. The Board also directs TransAlta to use the fixed amount “H” charge calculated using the 1998 pool price record and total 1998 TransAlta DISCO annual energy usage. This approach will, in the Board’s view, provide appropriate levels for each class’s annual average cost of energy and TransAlta’s “H” component. The Board considers that the resulting 1999 rates will provide better market signals than would rates based on the 1996 load data and 1996 pool price forecasts in the Application. The 1996 forecast is the only forecast available to the Board which is broken down into component costs. The Board also considers TransAlta’s 1996 forecast transmission costs outdated and therefore inappropriate for use in the rates arising out of this proceeding. The Board directs TransAlta to use the TA’s interim 1999 rates (as approved in Order U99018 dated 11 February 1999) and TransAlta DISCO’s actual 1998 TA invoiced kWh and kW to determine updated TA Billings. The allocation to rate classes and transmission served customer classes should use actual 1998 hourly class load and NCP data to determine the kWh and kW charges. TransAlta’s per kWh and kW charges to recover TA Billings will then reflect the 1999 TA rates which are adjusted for the effect of reallocating the 25 kV plant to transmission (See Section 3(c)). The Board also directs Decision U99035 Page 53 10 August 1999


TransAlta to indicate the separate charges for the TA Billings and DISCO Services components on each rate schedule. The total Energy Supply cost and the updated TA Billings will be different from TransAlta’s transmission and generation costs in the Application. The Board directs TransAlta to deduct the resulting total updated 1998 forecast costs of Energy Supply and updated TA Billings from TransAlta DISCO’s 1998 negotiated revenue requirement (as approved by the Board in Decision U98093) and use the resulting 1998 residual as the cost of TransAlta’s DISCO Services in the refiling. This will keep the price signals from the Energy Supply and TA Billings cost sources accurate, while allowing TransAlta to recover the 1998 DISCO revenue requirement negotiated with its customers. The Board also directs TransAlta to prorate the 1996 distribution cost allocations (as adjusted for the removal of the 25 kV costs from distribution) in the Application to the 1998 residual in the refiling to determine the levels for the DISCO Services components in the refiled rates. Further, the Board directs TransAlta to confine the entire effect of the across-the-board rider arising out of the 1998 settlement agreement to the DISCO Services components of TransAlta’s rates. For those customers served at the transmission level the effect of the across-the-board rider should be confined to the TA Billings components. While the foregoing procedure is not ideal with respect to determining appropriate DISCO Services costs, the Board considers that more accurate unbundled Energy Supply costs and TA Billings are available and should appear as unbundled charges in customer rates at this time. The DISCO Services cost is a residual and cannot be entirely cost reflective if TransAlta is to recover its1998 DISCO revenue requirement. The Board directs TransAlta to refile its COSS and rates on 1 September 1999. To confirm compliance to the Board’s directions, the Board directs TransAlta to supply tables setting out revenue-to-cost ratios for each rate by cost source (Energy Supply, TA Billings and DISCO Services) and to confirm that overall DISCO revenue-to-cost ratios by cost source are at 100%. (c) 100% Demand Ratchet

A demand ratchet is the mechanism in a rate that captures the increase in metered demand, and the consequent increase in costs, over the base demand that is used to calculate the billing for a customer. The ratchet works to ensure that the customer pays in a month demand charges based on the highest metered demand in a set period. In this Application TransAlta is seeking approval to raise its ratchet from 85% to 100%, ensuring that it will recover each month 100% of the demand charges payable based on the highest metered demand in the 12 month period including and ending with the billing period. The ratchet applies to the following demand metered rates:

• Rate 4100, Small General Service • Rate 4200, Small General Time of Use Service



• Rate 4400, Unmetered Oil and Gas Service • Rate 4500, Oil and Gas Time of Use • Rate 6100, General Service • Rate 6200, General Time of Use Service • Rate 6300, Large General Time of Use Service • Rate 6400, Transmission Service • Rate 6700, Real Time Pricing • Rate 6800, Direct Access Tariff


In proposing this change TransAlta offered no explanation in either its original Application or in its argument, it merely changed the wording of its rate schedules. In its reply TransAlta referenced the response to IPL-TAU.10 in which it stated that with the new industry structure and the unbundling of rates that demand charges now principally relate to dedicated and local supply facilities which are sized according to a customer’s peak demand. It is therefore appropriate for a customer to pay a charge relating to the size and cost of those facilities each month, even if in a particular month his demand is lower for some reason. Such a pricing principle is applied because it encourages the efficient use of facilities and avoids what would otherwise be a cross subsidy of low load factor customers by higher load factor customers. TransAlta also cited the need for rate stability and stated that a move from an 85% ratchet on rates with very significant demand charges, to a 100% ratchet on rates where the demand charge is a much smaller component of the rate, was considered reasonable and appropriate. Position of the Intervenors

IPCAA

IPCAA stated that TransAlta’s reasoning simply does not justify a 100% ratchet. It pointed out that the TA’s fixed charges are split 40% to demand (rate GIS) and 60% to on-peak energy (rate GSS). When loss charges are taken into account, the demand portion is less than 40%. The delivery service charges in Rates 6100-6300 are primarily demand related. In Rate 6400 they are purely demand charges. IPCAA maintained that there is simply no compelling reason to increase the ratchet. IPPSA/SPPA

IPPSA/SPPA stated that while TransAlta’s move to increase the ratchet may be consistent with the TA’s policy at the transmission distribution interface, it totally ignores load diversity for smaller commercial and industrial accounts. While there is a closer correlation between transmission costs and peak customer demands for larger industrial customers, there is significantly lower correlation for proposed Rate 4500 and 6100 accounts. For distribution costs, the same holds true. While some distribution assets are local facility related, a good portion form the “deep” distribution system. Collecting all wires demand charges with a 100% demand ratchet is inappropriate and only serves to reduce the revenue forecast risk for TransAlta. Decision U99035 Page 55 10 August 1999


IPPSA/SPPA maintained that TransAlta’s proposed tariff allows for the continued discrimination against oilfield customers compared to small commercial customers. A commercial customer on Rate 4100 may have an energy only meter with large demand swings, yet not be charged for the demand costs placed on the system. A similar oilfield customer on Rate 4400 or 4500, who has a load excursion for a period of a few minutes, could pay higher demand charges for 12 months. IPPSA/SPPA supported an 85% demand ratchet for Rates 4500 and 6100. IPPSA/SPPA also noted TransCanada’s point that if TransAlta’s proposed generation cost methodology is rejected by the Board and replaced with a peak demand allocation method, TransAlta may elect to propose demand related generation charges. If this is the direction the Board considers appropriate, then the Board should also consider directing TransAlta to design its small and mid-sized industrial rates with an appropriate demand ratchet of 85% or less. IPPSA/SPPA also supported the arguments made by TransCanada on the need for consistent polices related to the waiving of demand ratchets and adjusting demand histories. TransCanada

TransCanada noted that given TransAlta’s energy intensive pricing approach for generation costs, demand related charges in the industrial rates decline significantly and TransAlta has proposed to apply their 100% demand ratchet to Delivery service charges. TransCanada also noted that during the hearing TransAlta stated that the 85% ratchet was appropriate in the Old World because it dealt with a large amount of cost recovery, not only for local facilities but also for the deeper transmission and distribution systems and the generation system as well. TransCanada referred the Board to the positions of those intervenors who supported the 3W/9NW determine allocation method, as well as their own argument, and stated that should the Board decide the 3W/9NW method to be appropriate, there would be many implications on rate design, not the least of which would be the 100% demand ratchet proposed by TransAlta. TransCanada submitted that should the 3W/9NW method be adopted by the Board with the logical consequence of increased demand charges, then the 85% demand ratchet should be restored. TransCanada also commented on the waiving of demand ratchets and the adjustment of demand history, stating that in existing rates TransAlta waives the ratchets or adjusts demand history due to:

• Force majeure; • A once per service life exemption; • Construction type power, testing new plant equipment; • Restarting customer equipment after a power outage; and



• Installation of energy efficient equipment, such as capacitors or other energy efficient equipment.

TransCanada noted that in conjunction with TransAlta’s proposal to raise the demand ratchet to 100%, TransAlta does not have any policies in place to waive demand ratchets in the new rates. TransAlta would, however, review the TA’s policy as to any waivers or other similar relief that may be provided at TransAlta’s point of deliveries (POD). While TransAlta’s position might make some sense for Large General Service customers who are directly connected to TA POD, TransCanada maintained that it was inappropriate further downstream in the distribution system where there was more diversity, since the loads are unlikely to peak at the same time. TransCanada submitted that TransAlta’s premise for the change is that the ratchet is applied to a very small part of the bill and that local facilities remain in place year-round, regardless of whether the customer is using them or not. TransCanada responded that local transmission and distribution facilities are obviously in place year-round whether the customer uses them or not and whether we are in the Old World or the New World. TransCanada submitted that since the Transmission and Distribution systems are still under regulation, and in the absence of more compelling reasons for TransAlta to change its policies on waiving demand ratchets or adjusting demand history, TransAlta should be directed to maintain the previous applicable policies on this matter. TransCanada further submitted that any modifications arising from the TA’s policy as to any waivers in demand ratchets or similar relief provided at TransAlta’s PODs should be incorporated into TransAlta’s relevant policies. Board Findings

Since the Board has determined that all generation costs will be allocated on an energy basis, the demand ratchet will apply to a much smaller portion of a customer’s total bill. The Board considers that a demand ratchet of 100% for customers taking service at the transmission level appropriately passes through the TA’s rates. The Board notes the arguments of both IPPSA/SPPA and TransCanada that, while there may be a correlation between transmission costs and peak demand for large industrial customers taking service at the transmission level, TransAlta ignores the load diversity that exists for smaller industrial and commercial customers who take service at the distribution level. In light of the load diversity that exists at the distribution level the Board considers a demand ratchet of 85% appropriate for the TA Billings component of the rate for customers taking service at the distribution level. For such customers an 85% demand ratchet would also seem more appropriate for the DISCO Services components of the rate, since those components charge for marketing, metering and other DISCO Services not related to the size and cost of the distribution facilities. The Board directs TransAlta to make the necessary changes to its COSS and rate schedules. The Board notes the arguments of TransCanada, supported by IPPSA/SPPA, with respect to the need for consistent policies related to the waiving of demand ratchets and the adjustment of



demand histories. The Board also notes that TransAlta made no comments on these issues in its submissions. The Board considers the arguments of TransCanada to be reasonable. Therefore, the Board directs TransAlta to maintain its existing policies with respect to these matters for customers taking service at the distribution level. However, for customers taking service at the transmission level, the Board directs TransAlta to mirror any TA policies as to waivers of demand ratchet inherent in the TA’s rates. (d) Time-of-Use

TransAlta proposed that, wherever customer meters provided sufficient data, it would offer only TOU based energy charges. All services over 2000 kW and all new Oil and Gas services would be billed on TOU rates. TOU rates would be optional for residential, farm, irrigation, small general service and general service customers. IPCAA questioned the need for conversion of large customers to TOU rates, the level of the rates and the reason for such rates when there was a DAT. Position of TransAlta

TransAlta stated that its TOU rates represent a major improvement over the blocking of energy based on demand. As demonstrated in TAU-PICA.17(f), there is a clear differentiation in generation costs between the TOU periods. Similarly, there is a clear differentiation in TA rates (TA Rate GSS) between on and off peak periods. Consequently, TOU rates provide a clearer price signal to customers by reflecting the higher costs during peak hours and lower costs in off-peak hours. TransAlta also responded to IPCAA’s claim that Drazen Consulting’s evidence demonstrated that TransAlta’s proposed TOU charges bear no consistent relationship to actual market energy costs in the on-peak, shoulder and off-peak periods. TransAlta argued that the table presented on page 29 of Drazen’s written evidence (source: Schedule 14) did not clearly present the facts. Specifically, that the conclusion ultimately changes when the source of the data is considered. TransAlta submitted that Schedule 14 clearly demonstrates that peak prices are higher than shoulder prices, which in turn are higher than off-peak prices. The TOU charges proposed by TransAlta are consistent with the relative levels of 1998 actual pool prices, whether considering the winter or summer periods during the year. Finally, TransAlta responded to IPCAA’s recommendation to reject TOU rates due to the inaccuracy and volatility of pool price forecasts. TransAlta argued that TOU rates represent an averaging of prices over a period of time and averaging by its nature tends to eliminate the volatility as well as minimize the inaccuracy inherent in hourly forecasts.




IPCAA

IPCAA was critical of TransAlta’s proposal to use TOU rates. IPCAA argued that availability of hourly energy prices renders TOU design archaic. Although TOU rates may appear to represent an improvement over non-differentiated rates, IPCAA stated that this type of design has already been used and not proven to be successful. For example, the Large General Service TOU Rate 770 has represented an alternative to Rate 790 for several years. Following the introduction of Rate 770 in 1991, TransAlta stated in the 1992 Phase II Application that TOU should not increase system costs by encouraging undesirable load characteristics. Applying this logic, IPCAA confirmed that the rate has attracted only about 7% of the total Large Rate 790 load. Of particular interest, IPCAA provided evidence that the customers who have been attracted to choosing this rate have been customers who have less desirable load patterns25. Consequently, the load pattern for the Large Rate 770 customers is more on-peak than the load pattern for the Large Rate 790 class, contrary to the effect intended. According to IPCAA, the problem was that the TOU rate provided a perverse signal, with the result that a steady usage Rate 790 customer would have received a rate increase by switching to Rate 770. IPCAA submitted that the Drazen evidence showed that the proposed TOU charges bear no consistent relationship to actual market energy costs in the on peak, off peak and shoulder periods. In the summer months of May to July 1998, the proposed on peak energy charges were only 38%B65% of the average on peak energy cost, whereas the proposed off peak charges were 83%B105% of the average off peak energy cost. IPCAA pointed out that in reply to IPCAA.TAU-64 TransAlta stated that for Rates 6300 and 6400 an adjustment was made for customer behaviour changes moving from a kW blocked energy rate to a TOU blocked energy rate. This means that a customer that does not change usage will be charged a higher cost to offset the effect of the expected change. Given that the large Rate 790 class already has 63% of its usage in the off-peak period, this proposed adjustment is illogical. IPCAA also argued that TOU charges proposed in the Application have not reflected relative pool prices in various periods. For example, there has been no consistency with respect to Rate 6400 charges. IPCAA provided evidence that there is no consistent relationship in the ratio of the TOU generation supply charge for Rate 6400 to the actual average 1998 pool prices during various months of the year26. As a result, IPCAA stated that TOU generation supply charges are irrelevant to actual supply conditions. Thus, TOU charges provide ineffective signals during critical high-cost periods.

25 IPCAA’s Written Evidence, p.28, Table


26 IPCAA’s Written Evidence, p.29, Table


IPCAA was also critical of TransAlta’s 1998 pool price forecast, which was used to derive TOU charges. IPCAA argued that TransAlta’s pool price forecast for 1998 was inaccurate. Whereas TransAlta forecast $27/MWh for 1998, the actual-to-date pool price was over $32/MWh (to December 1998, while the annual average was $33.80/MWh). Due to forecasting inaccuracies and extreme volatility in pool prices, it is difficult for customers to receive the appropriate price signals to respond to. Given the extreme variability in pool prices IPCAA submitted that a proper question to ask is – what is a reasonable goal for the non-DAT generation charges? Drazen submitted that the purpose of the non-DAT rate should be to provide customers with good information so they can compare the two rates. TOU charges make it much harder for the customer to figure out what you are doing. The better goal then is comparability with the DAT rate as opposed to trying to give customers some signals that are really based on pool prices that are, at best, out of date and probably wrong. Customers should at least have a good basis for comparing the potential benefits of becoming price responsive users. Those that can respond to price signals can be expected to choose the DAT. Those that do not make that choice will nevertheless have had the opportunity to make an informed decision. In conclusion IPCAA recommended that it was not reasonable to introduce TOU rates at this point in time. IPCAA argued that two-period and three-period TOU blocking has been ineffective in motivating more efficient decisions in the past and is irrelevant in the present environment. Therefore, the Board should reject TransAlta’s proposal to use only TOU rates in the current Phase II proceeding. Board Findings

The Board agrees with TransAlta that TAU-PICA.17(f) indicates that there is a clear differentiation in generation costs between the TOU periods and notes the differentiation in TA rates (TA Rate GSS) between on-peak and off-peak periods. Therefore, TOU rates provide a clearer price signal to customers by reflecting the higher costs during peak hours and lower costs in off-peak hours and seasons. Further, the Board considers TransAlta is required by the EU Act to offer a fixed charge TOU DAT rate option. As noted in the DAT Section 4(a)13, the Board considers that TransAlta’s Rates 6200, 6300 and 6400 fulfill that requirement. However, the Board considers that the rates require considerable adjustment to be fair and reasonable. The Board shares IPCAA’s concerns that TOU rates must not result in perverse signals. The Board is also concerned that there be no premium in the TOU rates that might cause such an effect. As a general principle the Board does not consider that there should be any premium over forecast costs in any rate the Disco charges its customers. The risk that those costs may be higher or lower should be the DISCO’s risk, unless the customers agree to assume some of the risks or the Board determines a risk premium is appropriate. The risk to the DISCO of pool price variance from forecast on load exceeding the DISCO’s entitlements was considered to be the DISCO’s risk in Decision U97065. Therefore, the Board is not persuaded that there should be



any risk premium inherent in the DISCO’s TOU DAT rates or for that matter any other fixed rate arising out of this proceeding. The EU Act 31.6(2)(b) specifies that the charges to apply for certain hours reflect an expected average cost calculated using a forecast of pool prices for those hours. In Section 3(b) the Board concludes that the proper forecast for rates arising out of this proceeding should be based on the actual 1998 pool price record. The Board notes that if TransAlta were allowed to collect forecast 1998 pool prices on its TOU rates, while crediting TOU customers only the 1996 UOV refund levels, it would over-collect from customers on a net basis since 1998 UOVs will be higher than 1996. In the Section 4(a)13, the Board directed TransAlta to use the actual 1998 average on-peak/off-peak pool price as its on-peak/off-peak energy charge and the fixed amount “H” as calculated from the 1998 pool price record and total TransAlta DISCO annual energy use. The Board considers that this methodology, applied to TOU rates, will minimize the possibility of perverse price signals by providing appropriate forecast TOU energy charge differentials. To improve the efficiency of the demand side of the market, the Board would prefer that all large customers move to the actual pool price DAT and be exposed to the actual variation in pool price. The advantage to the actual pool price DAT is that customers would see and might respond to actual short term spikes in the pool price. However, the Board recognizes that some customers may not be prepared to move away from fixed rates at this time. In addition the Board agrees with TransAlta that properly forecast TOU rates provide superior price signals as compared to the single fixed rate IPCAA’s argument suggests. A single fixed rate can only reflect the forecast average cost of energy throughout all of the year for the entire class based on forecast average class consumption patterns. The TOU rate can reflect the average expected variation in pool price with the season, day of the week and time of the day and allows customers the opportunity to vary their actual consumption to take advantage of lower energy cost periods. The Board considers the efficiency of the market will be enhanced if all of TransAlta’s large customers see at least that expected variation in pool price. Therefore, the Board will not direct TransAlta to offer a single fixed rate for any services over 2000 kW.


TRANSALTA 1996 CPhase II

4. INDIVIDUAL RATES, OPTIONS AND RIDERS

(a) Rates

(1) Bid Temporary Energy Rate C Rate 720

Rate 720 is the current tariff under which customers receive temporary energy service. TransAlta has proposed to replace Rate 720 with Rate 6600 with no significant changes to be made to the tariff. The net revenue from this rate is allocated back to firm rate customers as a credit to the cost of service of these customer classes. Current Bid Temporary Energy customers are receiving a reduction of $2.50/MWh as part of the general refund arising from the 1998 Negotiated Settlement. This reduction was effective 1 June 1998. Some of the parties believe this to be a Phase II allocation issue and raised it in this proceeding. As Rate 720 is to be replaced by Rate 6600 it is the reduction received as part of the 1998 settlement that is the only issue with respect to Rate 720. Some parties have suggested that the reduction be eliminated, the temporary customers who have benefited from it repay all credits received from 1 June 1998 until final rates go into effect, and that the credits refunded be distributed to all firm rate customers. The total amount of the reduction is approximately $2.5 million on an annual basis. Position of the Intervenors

FIRM Customers

The FIRM Customers stated that they reluctantly agreed to include a reduction to Rate 720 temporary energy customers, as part of the 1998 Negotiated Settlement, and did so only under the condition that the issue could be examined as part of the Phase II proceeding. The FIRM Customers claimed this was made clear in the letter issued by Mr. Bryan on 28 May 1998. The FIRM Customers noted clause 7.2 of the settlement which states that TransAlta’s rate riders were to be interim and adjustable to the extent that changes in cost allocations to rate classes and/or changes to retail rates resulting from a Phase II proceeding and Board decision may result in revised retail rates and an adjustment by rate class to revenue collected or refunded by the rate riders. The FIRM Customers also noted the evidence of their consultant, Mr. Marcus, who described Rate 720 as a market based rate where customers accept the rate offered at the time they make their purchase decisions. The FIRM Customers submitted that the pool price would likely be lower without temporary energy sales and this higher price may offset some if not all of the contribution to fixed costs that Rate 720 customers provide. Applying the rate reduction to Rate 720 would send the wrong market signals to these customers. The FIRM Customers stated that the rate reduction afforded Rate 720 customers was unjustified and asked that it be reversed for the entire period, be collected from these customers and refunded to all firm customers. The FIRM Customers disputed IPCAA’s characterization of the reduction as being related to the “DISCO adder”, claiming that the negotiated settlement and the Board’s approval therefore


4. INDIVIDUAL RATES, OPTIONS AND RIDERS (a) Rates TRANSALTA 1996 CPhase II

contemplated a $2.50 per MWh reduction to Rate 720 without any suggestion that it related only to a DISCO adder. The adder relates to the contribution to the fixed costs of the existing infrastructure, including generation, transmission, and distribution. The distribution costs assigned to temporary customers are estimated to be only 4 mills. The FIRM Customers suggested that if there is to be any refund at all it should be limited to this amount. The FIRM Customers described sales under Rate 720 as opportunity sales. The customers have options and make choices, choosing to consume because the price offered is attractive at the relevant point in time. Just as these customers would not be expected to pay additional amounts if the utility had a revenue shortfall they should not be allowed to share the benefit of a refund. IPCAA

IPCAA submitted that the reduction should not be reversed, noting that Mr. Marcus acknowledged that Rate 720 customers are only allocated $41,000 in distribution expenses. Furthermore, Mr. Marcus has not offered any valid reason for the high level of the DISCO adder. Amoco

Amoco noted that the FIRM Customers had made no attempt to justify the level of the DISCO adder, outside of stating that it is meant to provide a contribution to fixed costs. Amoco also rejected the argument that it is important to consider the effect, if any, of temporary energy sales upon pool price, noting that the government has selected the market as the method for resolving supply and demand issues. Amoco submitted that, as long as temporary energy customers are compelled to make a contribution to fixed costs, they should be entitled to the reduction. Board Findings

The Board notes that clause 7.2 of the 1998 Negotiated Settlement states that all adjustments are subject to change as a result of changes in cost allocations resulting from this Phase II proceeding. The Board also notes that any change to this rate reduction would not affect total revenue requirement. Finally, the Board notes the letter of Mr. Bryan, dated 28 May 1998, to the Board, in which he expressed the objection of the FIRM Customers to this reduction. For these reasons the Board believes it is appropriate to consider this reduction as part of this proceeding. Notwithstanding the letter of Mr. Bryan, the Board notes that the FIRM Customers supported the negotiated settlement. As the Board was not part of the negotiations it cannot know what, if any, other accommodations or considerations the FIRM Customers took into account in supporting the settlement. The reduction to temporary energy customers will end, however, when the new rates take effect and Rate 720 is replaced by Rate 6600. The Board notes from the argument of IPCAA that Rate 720 contained a distribution charge of $12.50/MWh for the first 350 MWh and $1.50/MWh for all additional usage, even after allowing for a $2.50 per MWh reduction. The Board also notes that the rate recovers the full costs of both energy and transmission. Therefore, the Board considers it likely that the temporary energy Decision U99035 Page 63 10 August 1999


customers were making a contribution to fixed costs of distribution. The Board also believes that it would be unfair to go back to customers who have made economic decisions based upon the reduced rate and ask them to pay back the reduction they received. Therefore, the Board will allow the customers to retain the $2.50/MWh reduction. (2) Residential

TransAlta is proposing to replace its current Residential Rate 190 with two new residential rates described below. Current Residential Rate 190 includes an energy component of 7.584/kWh for all kWh consumed and a fixed monthly charge of $11.90. (A) Rate 1100 C Residential

Rate 1100 would include the following components: • a generation charge of 2.964/kWh for all kWh consumed, and • a delivery charge of:

• 3.144/kWh for all kWh consumed, and • a basic monthly charge of $16.00.

Two questions raised by Intervenors in regard to Rate 1100 are:

• Is the increase in basic monthly charge from $11.90 to $16.00 justified? • Should Rate 1100 be given a greater than average decrease to move the revenue/cost ratio

closer to unity? Position of TransAlta

TransAlta indicated that Rate 1100 received a greater than average overall rate decrease. The proposed residential rate has an approximate 20% decrease to the energy charge and a 34% increase in the customer basic monthly charge. In response to the CCA’s submission that there is no need to change the fixed monthly charge component from its current level of $11.90, TransAlta submitted that the CCA ignored the COSS and simply compared the fixed component of 25 other utilities without any consideration of the cost structure and investment policies of those utilities. TransAlta explained that its COSS classified $84.9 million to the fixed demand and customer components of the Residential Rate Class and $58.4 million to the energy component of the Residential Rate Class.27 However, TransAlta’s proposed residential rates would recover only $43.7 million from the fixed demand/customer component and more than $100 million from the energy component. Therefore, TransAlta submitted that the proposed increase in the basic monthly charge goes only part of the way (i.e. 51.4%) to recovering fixed transmission and distribution costs.


27 Table IPPSA.TAU-15-3.


In summary, TransAlta submitted that the appropriateness of its proposed basic monthly charge should be measured by reference to its cost of service and that the proposed $16.00 basic monthly charge was therefore appropriate. Position of the Intervenors

CCA

The CCA noted that TransAlta’s reason for its proposed increase to the Rate 1100 fixed charge was to better reflect the fixed cost of serving a residential customer. The CCA noted that TransAlta compared its proposed monthly fixed charge with those of TELUS Corporation (TELUS) ($22.61), Shaw ($17.00), and Canadian Western Natural Gas Company Limited (CWNG) ($14.00) to justify its proposed increase. The CCA indicated that, of the 25 public utilities sampled by TransAlta, the average monthly fixed charge amounted to $10.40 per month. Therefore, the CCA stated that TransAlta’s proposal of $16.00 a month was not justifiable. The CCA submitted that the proposal to increase the monthly fixed charge was simply an attempt by TransAlta to capture more of the revenues of the residential rate class from the non variable component of the rate, in effect, assuring the Company that approximately $11.5 million of revenue would not be subjected to the risk of variance in sales. The CCA also submitted that the higher the fixed charge component of the customer’s bill, the less incentive there is to conserve energy. Accordingly, TransAlta’s proposal provided an obtuse price signal for those Rate 1100 customers that wished to implement energy conservation measures. The CCA also submitted that TransAlta’s proposal to increase the fixed component of Rate 1100 sends signals contrary to those inherent in its COSS. The 1996 COSS used energy as the allocator for a number of generation costs that were, in previous cost of service studies, allocated based on demand or demand and energy. This shift, occasioned by the new industry structure, would suggest that the energy component of Rate 1100 should be higher. Instead, TransAlta’s rate structure proposal provides the opposite signal by reflecting greater weighting on the demand component. MI

The MI submitted that TransAlta proposed a slightly above average decrease of 7.6% for Rate 1100, which resulted in a revenue-to-cost ratio (based on its COSS) of 101.0%. The MI stated that the revised COSS proposed by the consultant to the FIRM Customers assigned approximately $4.5 million less cost to the residential rate class which justified a further reduction in rates from that proposed by TransAlta.



Board Findings

The Board notes that TransAlta’s proposed residential rates would recover less than the costs allocated to the rate class for the fixed components (demand and customer). Conversely, the rate would recover more from the energy component than the energy costs allocated to the rate class. Had TransAlta designed a residential rate that would have recovered costs according to the proportions of its COSS, the fixed component of the rate would have been significantly higher than the fixed component in its proposed residential rates. By recovering more costs from energy and less costs from demand/customer charges, TransAlta designed a residential rate that has a fixed monthly charge of only $16.00 but the rate nevertheless represents a cross-subsidy of the fixed components from the energy component. The Board recognizes the possibility that, in the future, wire ownership may be separated from energy sales, billing and metering activities. These latter functions may be carried out by an affiliate of the DISCO or by independent retailers selling directly to consumers. In either event, TransAlta DISCO’s wire cost may be largely recovered as a fixed component in the customer bill. Therefore, TransAlta’s proposed increase in the fixed charge of its residential rate might be justified as an appropriate price signal to prepare customers to accept future rates that directly reflect costs. Currently, TransAlta DISCO still carries out the functions of buying energy from the pool, selling energy to consumers, metering, and billing customers. Therefore, as a multi-function DISCO, TransAlta can still cross-subsidize costs within its functions as long as such cross-subsidizations result in rates that are just and reasonable. In this particular case, the Board notes that the proposed fixed monthly charge of $16.00 represents a 34% increase over the current residential rate’s monthly charge of $11.90. Although this is a large increase to implement all at once, given the likelihood that future industry restructuring will lead to higher fixed charges, the Board considers the increase to be appropriate at this time. The Board, therefore, approves TransAlta’s proposed monthly fixed charge of $16.00. In Section 3(a) of this Decision, the Board directed TransAlta to design rates so that



• the overall increase in revenue over that collected from existing rates is kept at less than 10% for every class, by adjusting as required the “residual” DISCO Services amounts to be recovered from customer classes. (The Board notes that individual customers may see more than a 10% increase if their usage characteristics warrant.)



The Board also directed TransAlta to include a table showing the revenue-to-cost ratios for each cost source (Energy Supply, TA Billings and DISCO Services) for each rate class. (B) Rate 1200 C Residential Time-of-Use

This rate includes the following components: • a generation charge of 3.314/kWh for all kWh consumed on-peak and 2.964/kWh for

all kWh consumed off-peak, • a delivery service charge component of:

• 7.334/kWh for all kWh consumed on-peak and no charge for kWh consumed off-peak, and

• a basic monthly charge of $19.30 per month.

On-peak periods are 8 a.m. to 9 p.m. Monday to Friday. Off-peak periods are all other periods including weekends.

The main issues raised by Intervenors with respect to Rate 1200 are:

• the cost of, and recovery of the cost of, TOU meters • the incentive to move from Rate 1100 to rate 1200.


CCA

The CCA submitted that there appeared to be some confusion on the part of TransAlta regarding the method used to calculate the $3.30 increase over the Rate 1100 basic monthly charge to cover the cost of the required TOU meter. The CCA submitted that TransAlta suggested that the calculation was based on the incremental cost (i.e. over the cost of the standard regular meter). However, TransAlta’s Exhibit 20 shows a proxy method. Further, the CCA indicated that while TransAlta stated at the hearing that the capital cost of the TOU meter was $370, TransAlta stated in response BR.TAU-10(b) that the cost was $275.00. Therefore, the CCA submitted that TransAlta may have overstated the $3.30 differential in the monthly basic fixed charge. The CCA submitted that an examination of Exhibit 2 (Table COS A4.0) indicates that the cost differential included distribution related operating expenses, capital related expenses (depreciation expense, income taxes, return) and revenue offsets. The capital related distribution expenses might have little or no bearing on the capital related expenses associated with a TOU meter. The CCA also noted that the operating expenses included a wide range of expenses, including marketing, G&A, customer accounting, other taxes, brushing expenses as well as other O&M expense that might be irrelevant to the costs of installing and operating a residential TOU meter.



Therefore, the CCA submitted that the Board should direct TransAlta to provide, at its next GRA, a detailed calculation of the factors that support the $3.30 differential in the monthly fixed charge between Rate 1200 and Rate 1100. The CCA expressed concern that the design of the proposed Rate 1200 may not provide any incentive for residential customers to make a transition from Rate 1100 to Rate 1200. The CCA noted TransAlta’s testimony that, of some 220,000 residential customers, there is only a handful of customers on the existing residential TOU rate. The CCA was not convinced that the proposed Rate 1200 would be any more enticing. The CCA submitted that, for example, simply to break even with Rate 1100, a customer would have to switch 40 kWh from on-peak to off-peak hours and if 75 kWh are switched from on-peak to off-peak hours, the savings would amount to less than $2.75 per month. The CCA concluded that, as there is not enough load in a typical residence that can be shifted from on-peak hours to off-peak hours, the proposed design of Rate 1200 makes it improbable that anybody will move from Rate 1100 to Rate 1200, thus frustrating the desired objective of providing the proper price signal of reducing the amount of on-peak usage. Therefore, the CCA requested that the Board direct TransAlta to propose, at its next GRA, a better residential TOU rate that would produce the desired objective of reducing the on-peak usage. The CCA indicated that implementation of a better residential TOU rate is important if there is to be any hope for customers in the residential rate class to opt for a future direct access rate. Position of TransAlta

TransAlta indicated that the basic monthly charge had been increased by $3.30 from Rate 1100 to cover the additional cost of TOU meters. Respecting the CCA claim that there is confusion on TransAlta’s part regarding the cost of TOU meters, TransAlta indicated that the support for the calculation of the premium ($3.30) included in Rate 1200 for TOU metering was clearly set out in Exhibit 20. In response to the CCA submission that Rate 1200 may not provide any incentive for Residential customers to make a transition from Rate 1100, TransAlta submitted that the objective should not be to provide an incentive to switch to Rate 1200, but to make available a TOU option for residential customers with appropriate price signals. In this regard TransAlta submitted that its proposed Rate 1200 provides the appropriate price signals, as they are based on a forecast of 1998 generation costs. Board Findings

The Board notes that TransAlta’s $3.30 premium over its proposed basic monthly charge is intended to recover the incremental cost of TOU meters over standard meters. The premium was calculated using a TOU meter cost of $275 as shown in Exhibit 20. The Board also notes TransAlta’s statement in Exhibit 20 that, if it adopts a slightly more expensive TOU meter



($370), which may be used not only for residential customers but also for farm, irrigation, and oil and gas services, it does not intend to increase the $3.30 per month applied to residential and farm TOU services. Therefore, the Board does not recognize any confusion regarding the cost of TOU meters as expressed by the CCA. TransAlta calculated the annual cost of TOU meters as 16.6% of the total incremental cost of TOU meters. The 16.6% factor was derived as the ratio of total annual distribution costs allocated to farm and residential customers over total distribution property allocated to farm and residential customers. The CCA objected to TransAlta’s approach on the grounds that capital related distribution costs, which are part of the total annual distribution cost, might have little or no bearing on the capital related expenses associated with a TOU meter. The CCA also suggested that some components of operating expenses, such as marketing, G&A, customer accounting, other taxes, and brushing expenses may be irrelevant to the costs of installing and operating a Residential TOU meter. The Board is not persuaded by the CCA that TransAlta’s approach in calculating the premium necessary to recover the incremental cost of TOU meters is unreasonable. Accordingly, the Board approves TransAlta’s use of a $3.30 premium in Rate 1200 over the basic monthly charge determined by the Board for Rate 1100. The Board agrees with the CCA’s position that Rate 1200 may not prove cost effective as there is not enough load in a typical residence that can be shifted from on-peak hours to off-peak hours. However, the Board notes that Rate 1200 is an optional rate for residential customers who may be able to manage their consumption to reduce their electricity bill. Since the components of the rate not related to energy supply are based on Rate 1100 as adjusted for the TOU meters, the Board accepts TransAlta’s design of Rate 1200. However, the Board also directs TransAlta to adjust the level of the TOU differential in its Energy Supply charges in the refiling to reflect the Board’s finding in Section 2(a)(1) of this Decision. (3) Farm

TransAlta proposed the following rates be available to its farm customers: (A) Rate 2100 C Farm Service

TransAlta proposed to replace its existing Farm Rate 300 with new Rate 2100 which would be available in rural areas to customers involved in a farming operation that includes a residence. Current Farm Rate 300 has the following components:

• an energy charge of 5.594/kWh, and • a demand charge of $28.70/month for the first 5 kVA of capacity per month and

$4.85/kVA/month for all capacity above 5 kVA.



Proposed Rate 2100 would consist of: • a generation charge of 2.954/kWh • a delivery charge of:

• 1.734/kWh, and • a fixed demand charge of $27.00/month for the first 5 kVA of capacity and

$3.07/kVA/month for all additional kVA. (B) Rate 2200 C Farm Time-of-Use Service

TransAlta proposed that new Rate 2200 Farm TOU Service be available in rural areas to customers who are involved in a farming operation, that includes a residence, and have approved TOU metering. Rate 2200 would replace TransAlta’s existing TOU Farm Rate 370, which has the following components:

• an energy charge of 8.754/kWh (consumed from 8 a.m. to 4 p.m.) plus 5.594/kWh (consumed from 4 p.m. to 9p.m.) plus 3.54/kWh (consumed from 9 p.m. to 8 a.m.), and

• a demand charge of $28.70/month for the first 5 kVA of capacity and $4.85/kVA/month for all capacity above 5 kVA.

Proposed Rate 2200 would consist of:

• a generation charge of 3.314/kWh for all kWh consumed on-peak and 2.704/kWh for all kWh consumed off-peak, and

• a delivery service charge component of: • 4.254/kWh for all kWh consumed on-peak, no charge for kWh consumed off-

peak, • a fixed charge of $30.30/month for the first 5 kVA of capacity, and

$3.07/kVA/month for all additional kVA.


(C) Rate 2300 C Grain Drying Service

TransAlta proposed that Rate 2300, Grain Drying Service be available to customers who have, in addition to the regular farm service, varying load levels throughout the year due to the use of a grain dryer for part of the year. Rate 2300 would replace TransAlta’s existing Rates 41X–48X (Grain Drying) that consist of:

• an energy charge of 5.594/kWh, and • a demand charge of $4.38/month for the first block and $0.45/month for the last

block.



Proposed Rate 2300 would consist of: • a generation charge of 2.904/kWh, • a delivery charge of:

• 2.004/kWh, and • a fixed charge of $24.50/month for the first 5 kVA of capacity, and

$3.50/kVA/month for all additional kVA. Position of the Intervenors

Participants did not raise any specific issues respecting Rate 2100, Rate 2200, or Rate 2300. However, some intervenors raised the issue of Company Farm Rates 2100 and 2200 being designed to give TransAlta a competitive advantage over Rural Electrification Association (REA) Farm Rates 2400 and 2500. The views of intervenors respecting this issue are presented in Section 4(a)(4), which deals with REA Farm rates. Board Findings

The Board addresses the issue of the effect competitive pressures would have on the design of Company Farm Rates 2100 and 2200 in the REA Farm Rates 2400 and 2500, Section 4(a)(4). In Section 3(a), the Board directed TransAlta to design rates so that




The Board also directed TransAlta to include a table showing the revenue-to-cost ratios for each cost source (Energy Supply, TA Billings and DISCO Services) for each rate class. (4) REA Farm Service

TransAlta proposed the following rates be available to members of REA and to farmers who own their entire electric service extension (T-rurals). A greater than average decrease is proposed for this rate class to move the revenue-to-cost ratio closer to unity. TransAlta stated that the proposed TOU rate will give REA farm customers greater control over their electricity bills. TransAlta has also proposed to eliminate the Large Farm REA Rate 320 as no customers were taking service on this rate.



(A) Rate 2400 C REA Farm Service

Rate 2400 includes the following components • a generation charge of 2.954/kWh, • a delivery charge of 1.734/kWh, and • charges collected for and on behalf of REAs and farmers who own their entire

electric service extension (T-rural). Rate 2400 replaces existing REA Rate 310, which consists of:

• an energy charge of 5.594/kWh, and • charges collected for and on behalf of REAs and farmers who own their entire

electric service extension (T-rural). (B) Rate 2500 C REA Farm Time-of-Use Service

Rate 2500 is available for customers eligible for Rate 2400 that have approved TOU metering. Rate 2500 consists of:

• a generation charge of 3.314/kWh for all kWh consumed on-peak plus 2.704/kWh for all kWh consumed off-peak,

• a delivery service charge component of 4.254/kWh for all kWh consumed on-peak and no charge for kWh consumed off-peak, and

• charges collected for and on behalf of REAs and farmers who own their entire electric service extension (T-rural).


Rate 2500 replaces existing REA TOU Rate 390, which consists of

• an energy charge of 8.754/kWh (consumed from 8 a.m. to 4 p.m.) plus 5.594/kWh (consumed from 4 p.m. to 9 p.m.) plus 3.54/kWh (consumed from 9 p.m. to 8 a.m.), and

• charges collected for and on behalf of REAs and farmers who own their entire electric service extension (T-rural).

The issue raised with respect to Rates 2400 and 2500 is whether or not Rates 2400 and 2500 would give TransAlta a competitive advantage over service offered by REAs. Position of the Intervenors

FIRM Customers

The FIRM Customers submitted that TransAlta proposed very different revenue-to-cost ratios for its company farm and REA farm customers. Under TransAlta’s proposed rates, after revisions due to allocation of 25 kV distribution costs, the farm revenue-cost ratio is 107.2%, while REA is 112.4%. The FIRM Customers recommended that Company Farm and REA Farm Decision U99035 Page 72 10 August 1999


rates be set with comparable revenue-to-cost ratios. The FIRM Customers submitted that an REA rate with a revenue-cost ratio 10 percentage points higher than the Company Farm rate would result in a rate design that is not cost-justified and would give TransAlta a competitive advantage to buy out REA’s. The FIRM Customers also submitted that the specifics of TransAlta’s rate design, unbundled to generation, transmission, and distribution, shows that the revenue-cost ratio for generation is close to 100%, but both farm and REA customers have a 150% revenue-cost ratio for transmission. In contrast, the distribution component of the rates for the Company Farm class has a revenue-cost ratio of only 88%. The FIRM Customers recommended that both Company Farm and REA Farm should have a common revenue-cost ratio of 106%. REA/AAMDC

The REA/AAMDC submitted that TransAlta’s proposed rates would give it a significant advantage over REAs and that there should be no subsidization of distribution costs in favor of TransAlta. The REA/AAMDC also submitted that TransAlta provided no justification for a rate design that, in its opinion, was self serving and objectionable. The REA/AAMDC submitted that, although the revenue-to-cost ratio for the combined generation and transmission system is the same for REA and TransAlta farms, it is not equitable as between the REA Farm and Company Farm customer classes and other classes. The REA/AAMDC submitted that the 150% revenue-to-cost ratio for the transmission function allocated to all farm customers enables TransAlta to design a rate which subsidizes the distribution function to enhance TransAlta’ competitive advantage. The REA/AAMDC also disputed TransAlta’s submission that REAs and their members benefit financially from grants and long-term interest free loans. The REA/AAMDC explained that it was a matter of public policy that the provincial government provided loans, grants, or other help to REAs, that these loans and grants were a remnant of the 1970s, and that all that is left is the interest earned and unspent. Furthermore, the REA/AAMDC submitted that, if the Board gives effect to TransAlta’s argument on the point of aid provided by government, it would have the affect of allowing TransAlta to reverse, through rate design, a public policy that the government has deemed proper and beneficial. Position of TransAlta

TransAlta submitted that the submissions by the FIRM Customers and the REA/AAMDC that the REA Farm and TransAlta Farm rates were designed in a fashion to give TransAlta a competitive advantage are not supported by the evidence. TransAlta indicated that, the total costs for REA Farms include costs of generation and transmission only and that in Rates 2100, 2200, 2400 and 2500, both TransAlta and REA Farm customers pay the same amount for generation



and transmission. Therefore, TransAlta submitted that the revenue-to-cost ratio for the combined generation and transmission system is equitable as between the REA and TransAlta rates and that this was consistent with evidence submitted on behalf of the FIRM Customers. With respect to the distribution components of each of the Farm Rates, TransAlta disputed the assertion that because REAs charge 100% of the cost of distribution functions, TransAlta Farm rate should do likewise. TransAlta submitted that REAs and their members benefit financially from grants and long-term interest free loans such that they do not pay 100% of the distribution-related costs to serve them. Furthermore, TransAlta submitted that recipients of grants benefit from the full value of the grants and recipients of long-term interest free loans benefit from the time value of money on the loan amount. Therefore, TransAlta submitted that the revenue-to-cost ratio for an REA distribution system is, in fact, less than 100%. In summary, TransAlta submitted that REA customers, like TransAlta farm customers, do not pay all of the distribution costs incurred to serve them and therefore, its proposed rates do not provide TransAlta with a competitive advantage. Board Findings

The Board considers that unbundling company farm rates into Energy Supply, TA Billings and DISCO Services cost sources reveals significant cross-subsidization of the DISCO Services costs by the TA Billings component. The Board is of the view that the government grants and interest-free loans to REAs are matters of government policy and should not affect the design of TransAlta’s company farm rates. TransAlta’s rates should be cost based. In Section 3(a), the Board directed TransAlta to design rates so that




The Board also directed TransAlta to include a table showing the revenue-to-cost ratios for each cost source (Energy Supply, TA Billings and DISCO Services) for this rate class. The Board also directs TransAlta to adjust the level of the TOU differential on its Energy Supply charges in the refiling to reflect the Board’s finding in Section 2(a)(1) of this Decision.



(5) TransAlta Irrigation

TransAlta proposed that rates 2600 and 2700 be available to its customers who have individually metered motors driving irrigation pumps that operate only in the irrigation season. (A) Rate 2600 C TransAlta Irrigation Service

This rate would replace current Rate 530, which consists of an energy charge of 5.594/kWh and a demand charge of $9.00 per kW of installed capacity per season. Proposed Rate 2600 would consist of:

• a generation charge of 2.834/kWh, • a delivery charge of:

• 2.804/kWh, • a fixed demand charge of $14.50/kW/season, and • an idle service charge of $13.50/kW/season.

(B) Rate 2700 C TransAlta Irrigation Time-of-Use Service

TransAlta’s proposed Rate 2700 would be available to customers who qualify for Rate 2600 and have approved TOU metering. This rate would replace existing Rate 510, which consists of energy charges of 8.754/kWh consumed on-peak, 4.154/kWh consumed off-peak , and a demand charge of $9.00 per kW of installed capacity per season. Rate 2700 would consist of:

• a generation charge of 3.204/kWh for all kWh consumed on-peak and 2.604/kWh for all kWh consumed off-peak,

• a delivery service charge component of: • 7.304/kWh for all kWh consumed on-peak, no charge for kWh consumed off-peak, • a demand charge of $14.50/kW/season, and • an idle service charge of $13.50/kW/season.


The issue raised by Intervenors respecting Rates 2600 and 2700 concerned the concept of rate shock. Position of the Intervenors

AIPA

AIPA submitted that TransAlta proposed an effective 19% increase in the present irrigation rates. It indicated that, at existing irrigation rates, TransAlta would collect $9.5 million while under proposed rates 2600 and 2800 (REA Irrigation rate) TransAlta would collect



$11.1 million. Furthermore, AIPA submitted that the irrigation rates are the only rates for which TransAlta has proposed an increase in this proceeding and that this increase is not justified in terms of stranded investment, revenue-to-cost ratios, and historical cost allocations. AIPA submitted that, according to TransAlta’s revised cost of service evidence, irrigation rates have a revenue-to-cost ratio of 75% and that this is a large and significant increase from the revenue-to-cost ratio of 60.1% approved in the last decision of the Board. AIPA submitted that, at the existing revenue-to-cost ratio of 60.1%, irrigation revenues in this proceeding, based on TransAlta allocated costs, would be $8.9 million or some $2.2 million less than the $11.1 million proposed. Furthermore, in the 1980s irrigation service cost allocations were on the basis of one-coincident-peak allocation method for generation and transmission and, on this basis, the TransAlta irrigation cost of service would be reduced further down to $7.7 million. AIPA submitted that, as part of its rate design criteria, TransAlta suggested that its rates should consider the rates and practices of other utilities having similar types of load and service conditions. Accordingly, TransAlta provided comparisons of irrigation bills for neighboring utilities that revealed, for instance, that TransAlta irrigation bills are 150% higher than British Columbia’s and 42% higher than Saskatchewan’s. Further, AIPA submitted that, to check whether these large differences between TransAlta and the neighboring utilities could be attributable to different cost structures, it attempted to “normalize” these comparisons. The normalization procedure was to compare irrigation bills with farm service bills within each utility. Results showed that for B.C. Hydro the annual irrigation bill was 136% of the annual farm service bill, for SaskPower the annual irrigation bill was 208% of the annual farm bill. However with TransAlta’s proposed rates the annual irrigation bill is 323% of the annual farm bill. AIPA also submitted an example comparing the electric bills, expressed in cents per kWh, for each of farm and irrigation service consuming 1,400 kWh/month and 55,800 kWh/season respectively for TransAlta, B.C. Hydro, and SaskPower. AIPA’s comparison showed that farm unit energy rates for the neighboring utilities are in the range of -6% and +9% of TransAlta’s. However the irrigation unit energy rates of the neighboring utilities are significantly less than TransAlta’s unit energy rates, in a range of 30–60% below TransAlta’s proposed rates. Therefore, AIPA submitted that the comparison to other utilities clearly supports a reduction to TransAlta’s proposed irrigation rates and revenues. Moreover, AIPA submitted that its comparison provided further support to the approach to rate design used in the evidence supported by the FIRM Customers. This evidence proposed that annual Company and REA irrigation revenues should be $9,960,000 resulting in an average unit rate of 7.14/kWh which should be an upper limit on what is reasonable in terms of neighboring utilities’ rates. In conclusion, AIPA submitted that, for Rate 2600, TransAlta proposed to increase the fixed charge from $9.00/kw/season to $14.50/kw/season and to increase the energy charge from 5.594/kWh to 5.634/kWh. Therefore, AIPA recommended that the energy charges remain as proposed but that the fixed charge be reduced to satisfy the Company irrigation portion of the Decision U99035 Page 76 10 August 1999


recommended revenue level of $9,960,000 (including both Company and REA irrigation revenues). FIRM Customers

The FIRM Customers noted that irrigation loads were encouraged in the past when a single winter peak was used as the basis for cost allocation. However, in the late 1980s the cost structure moved away from a single winter peak to the 3W/9NW method and TransAlta’s current proposal further changed the cost structure leading to an even flatter cost allocation. The FIRM Customers submitted that, as a result of the change in cost structure, irrigators have had a relatively low revenue-to-cost ratio and, as a result, since 1990 new irrigators were required to pay the full cost of their facilities as customer contributions. However, a relatively large percentage of irrigation costs involve return, taxes, and depreciation on systems installed under the old policy in the 1980s. Therefore, the FIRM Customers submitted that, as a result of this change in investment policy, it would not be equitable to raise the revenue-to-cost ratio to unity for those irrigators who came on the system in 1990 or later, as they would be charged return and taxes on property they had to contribute to in its entirety. Furthermore, the FIRM Customers also submitted that, in light of the competitive nature of the irrigation service, it would not be reasonable to charge the full cost to irrigation customers who came on line before 1990. The FIRM Customers, therefore, recommended that a new cost of service target be explicitly established for Company irrigators as the basis for rates going forward and that the Board should set a target so irrigation rates are ultimately set to recover the full cost of generation and transmission plus distribution O&M costs. However, allocated costs should not include the return, taxes, and depreciation associated with distribution plant since such plant was built before the no-contribution rule was put in place. In summary, for purposes of the current Application, the FIRM Customers recommended Company irrigation receive a 4.1% increase on prorated 1996 rates, moving it approximately 75% of the way towards the target. Position of TransAlta

TransAlta disputed the FIRM Customers’ recommendation for removal of return, taxes, and depreciation from distribution costs in the COSS and the FIRM Customers’ recommendation that a reduction be made to TransAlta’s proposed rate increase for its Irrigation customers. TransAlta pointed out that the FIRM Customers based its recommendation on the fact that TransAlta no longer makes investments in dedicated facilities for irrigation services. However, TransAlta submitted that irrigation customers, like all distribution customers, use existing distribution infrastructure and should therefore pay a share of the capital costs of that system. Furthermore, TransAlta submitted that the fact that TransAlta no longer invests in dedicated facilities does not mean that TransAlta will no longer make investments in the distribution system infrastructure.



Therefore, TransAlta submitted that capital costs allocated in the COSS are properly borne by all customers, including those in the Irrigation rate class. In response to AIPA’s submission that comparisons between the rates of neighboring utilities support a reduction to TransAlta’s proposed irrigation rates and revenues, TransAlta noted that AIPA did not provide the Board with an indication as to the revenue-to-cost ratios underlying the rates compared. Therefore, TransAlta submitted that without knowing the degree of cross-subsidization inherent in the rates of B.C. Hydro and SaskPower, meaningful comparison to the TransAlta Irrigation rate could not be made and therefore, such comparison should not form the basis for an adjustment to TransAlta’s proposal. TransAlta noted that it limited its proposed rate increase to irrigation customers to 10% to achieve a reasonable balance between rate stability and cost causation, and therefore, its rates, as proposed, were fair and reasonable and should be approved. Board Findings

The Board notes that the revenue-to-cost ratios and the degree of cross-subsidization in the rates of other provinces are not known. The Board considers that since irrigation customers use existing Alberta infrastructure they should pay a fair share of the capital costs. The Board notes that in the past the revenue-to-cost ratio was about 60% and TransAlta has proposed Irrigation Rates that have a 75% revenue-to-cost ratio in order to avoid significant rate shock to irrigation customers. In Section 3(a), the Board directed TransAlta to design rates so that




The Board also directed TransAlta to include a table showing the revenue-to-cost ratios for each cost source (Energy Supply, TA Billings and DISCO Services) for this rate class. The Board also directs TransAlta to adjust the level of the TOU differential in its Energy Supply charges in the refiling to reflect the Board’s finding in Section 2(a)(1) of this Decision.



(6) REA Irrigation

TransAlta proposed the following rates be available to members of REAs and to farmers who own their entire electric service extension (T-rural) for individually metered motors driving irrigation pumps that operate only in the irrigation season. (A) Rate 2800 C REA Irrigation Service

Rate 2800 would consist of: • a generation charge of 2.834/kWh, • a delivery charge of 2.804/kWh, and • charges collected for and on behalf of REAs and farmers who own their entire electric

service extension. (B) Rate 2900 C REA Irrigation Time-of-Use Service

TransAlta’s proposed Rate 2900 would be available to customers eligible for Rate 2800 who, in addition, have approved TOU metering. Rate 2900 would consist of

• a generation charge of 3.204/kWh for all kWh consumed on-peak plus 2.604/kWh for all kWh consumed off-peak,

• a delivery service charge component of 7.304/kWh for all kWh consumed on-peak and no charge for kWh consumed off-peak, and

• charges collected for and on behalf of REAs and farmers who own their entire electric service extension.

On-peak periods are 8 a.m. to 9 p.m. Monday to Friday. Off-peak periods are all other periods including weekends

Rates 2800 and 2900 would replace existing REA Irrigation Rate 540, which consists of an energy charge of 3.1654/kWh plus charges collected for and on behalf of REAs and farmers who own their entire electric service extension. The issues raised by Intervenors respecting Rates 2800 and 2900 are:

• rate shock, as TransAlta is proposing a 78% increase to REA irrigation rates, and • the proposal to grandfather existing REA irrigators and approve Rates 2800 and 2900 for

new REA irrigators only. Position of the Intervenors

FIRM Customers

The FIRM Customers submitted that the same principles suggested for Company irrigation should apply also to REA irrigators, i.e., that generation and transmission costs should be recovered from REA irrigators. The FIRM Customers submitted that TransAlta’s proposed REA irrigation rate would achieve this principle with a revenue-to-cost ratio within one percentage



point of 100% when using their recommended cost of service analysis. However, the FIRM Customers noted that this rate change would translate into a rate increase of 78% for the very few existing REA irrigators and therefore, it should not be adopted for all REA irrigators at this time. Instead, the FIRM Customers submitted that the existing REA irrigation customers should be grandfathered, i.e., that the current REA irrigation rate should be kept for existing REA irrigators but that it should be closed to new customers, that it should be increased by only 10% at this time, and that further increases should take place over a period of time in order to bring the grandfathered rate closer to cost recovery. The FIRM Customers also submitted that a new REA irrigation rate, applicable to all future customers, should be established at the level proposed by TransAlta. REA/AAMDC

In response to TransAlta’s submission that grandfathering existing REA Irrigation customers would be discriminatory, REA/AAMDC submitted that this proposal is not “unjustly discriminatory”, which is the language used in section 51(l)(c) of the EU Act. However, REA/AAMDC noted that TransAlta itself discriminates between existing and new irrigation customers with its investment policy. REA/AAMDC submitted that the problem with the current low revenue-to-cost ratio for REA irrigation indicated that the original design of rates for this service might have been wrong. However, if TransAlta was in error, REA irrigators were nevertheless lured to the rate and it would be unfair to allow TransAlta to revise the rate at this stage at the expense of REA members. Therefore, REA/AAMDC suggested that it would not be unjustly discriminatory to implement the proposal to grandfather existing REA irrigation customers as a means to protect existing customers while, concurrently, warning new customer that circumstances have changed and that for new customers the cost will be higher. REA/AAMDC also submitted that TransAlta should bear the cost of grandfathering existing REA irrigation customers as it was TransAlta who designed the original rates. Respecting TransAlta’s suggestion that SouthAlta REA is free to subsidize its members, REA/AAMDC submitted that SouthAlta REA has 56 irrigation members over half of which became members in 1997 and 1998. Therefore, SouthAlta had no control over the design of the generation or transmission portions of irrigation rates, it had no knowledge of the impending rate increases for irrigators, it was not able to warn its irrigation members about TransAlta’s proposals, and with under 2000 members it is not able to protect a segment of its members from a price increase as TransAlta suggested. AIPA

AIPA’s position regarding Irrigation Rates 2600 and 2800 is addressed in previous Section 4(a)(7) TransAlta Irrigation Rates 2600 and 2700.




TransAlta submitted that the REA Irrigation energy charges were set equal to the TransAlta Irrigation energy charges and that they were intended to recover TransAlta’s generation and transmission costs. TransAlta submitted that the FIRM Customers suggestion that TransAlta close and maintain the existing REA rate for current customers and opens a new rate for new customers was discriminatory. Further, TransAlta noted that the SouthAlta REA was an electrical distribution company engaged in construction, maintenance and accounting and that there was no requirement for the SouthAlta REA to flow TransAlta’s rates directly through to its members. Therefore, TransAlta submitted that if, as a distribution utility, the SouthAlta REA wished to protect a segment of its customers from an increase in electricity costs, it was free to do so. TransAlta also submitted that its Phase II filing results in lower overall costs to SouthAlta REA notwithstanding the increase in REA Irrigation Rates. Board Findings

The Board notes that TransAlta’s proposed REA Irrigation Rates represent an increase of more than 70% from existing rates.28 The Board is of the view that this is an excessive increase and is also contrary to TransAlta’s own rate design criteria to limit rate increases to about 10%. However, the Board considers that new customers who are assessing whether or not to invest in electric irrigation pumping equipment should be given the appropriate price signal. That will enable new customers to make a rational economic decision. To avoid rate shock to existing customers while providing a proper cost signal to new customers, existing customers will be grandfathered through a closed rate which will, over time, be brought up to the level of the rate available to new customers. The Board notes that this is not the only instance where existing customers are grandfathered on a closed rate and considers this to be an example where discrimination between customers is not unjust. The Board does not agree with the REA/AAMDC suggestion that the difference in revenues collected between TransAlta’s proposed rate and the grandfathered rate approved by the Board be borne by TransAlta. Such differences are more appropriately offset by other rate groups. Therefore, the Board directs TransAlta to design a rate along the lines suggested by the FIRM Customers whereby existing REA irrigation customers are grandfathered in a closed rate that would increase by no more than 10%. The Board approves TransAlta’s design of Rates 2800 to be applicable to new REA irrigation customers only. The Board also directs TransAlta to adjust the level of TOU differential on its


28 Revenue at existing rate (approximately $12,000) versus revenue at proposed rates (approximately $21,000)


Energy Supply charges in the refiling to reflect the Board’s finding in Section 2(a)(1) of this Decision. (7) Exterior Lighting

(A) Rate 3100 C Street Lighting Service (Investment Option)

Rate 3100 is proposed to be available for standard street lighting fixtures. TransAlta would be responsible for all maintenance costs. Rate 3100 would consist of:

• a generation service charge of 1.004 per watt per month, • a delivery service charge of:

• 0.854 per watt per month, and • a fixture charge of $13.70 per fixture per month.

Wattage Charges would not apply if the fixture is temporarily disconnected or if TransAlta supplies energy to the customer through a separately metered service. Rate 3300 also covers routine luminaries’ maintenance. (B) Rate 3300 C Street Lighting Service (No Investment Option)

Rate 3300 would be available for street and highway lighting fixtures and includes maintenance of the luminaries only. Street lighting customers might choose this rate for new installations only. Rate 3300 would consist of:

• a generation service charge of 1.004 per watt per month, • a delivery service charge of:


Wattage Charges would not apply if the fixture is temporarily disconnected or if TransAlta supplies energy to the customer through a separately metered service. Rate 3300 also covers routine luminaries’ maintenance. (C) Rate 3700 C Festive Lighting Service

Rate 3700 would be available to Municipalities who require decorative lighting for the Christmas season or other festive occasions during the months of December through February as follows:

• no charge if the Municipality installs festive lighting up to 15% of its total street lighting wattage for a six week period, and

• a wattage charge of $1.00 per kW per day for wattage in excess of 15% of its total street lighting wattage.



(D) Rate 3800 C Yard Lighting Service

Rate 3800 would be available to customers who require yard lighting. TransAlta would be responsible for all maintenance costs. Rate 3800 would consist of:

• a generation service charge of $1.00 per watt per month, • a delivery service charge of:


Wattage Charges would not apply if the fixture is temporarily disconnected or if TransAlta supplies energy to the customer through a separately metered service. Position of the Intervenors

MI

The MI indicated that TransAlta’s proposed exterior lighting rates would move the revenue-to-cost ratio from 132% to 118%. However, based on the cost of service analysis proposed by the FIRM Customers, the MI submitted that the revenue-to-cost ratio should be decreased further to 115%, which, in its opinion, was still high compared to other rate classes (except Small General service). Board Findings

In Section 3(a), the Board directed TransAlta to design rates so that • the DISCO’s total charges related to Energy Supply, TA Billings and DISCO

Services are unbundled, with the revenue-to-cost ratio for each set at 100%. • the revenue-to-cost ratios for Energy Supply and TA Billings are each set at 100%

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


The Board also directed TransAlta to include a table showing the revenue-to-cost ratios for each cost source (Energy Supply, TA Billings and DISCO Services) for this rate class. (8) Small General and Temporary Services

(A) Rate 4100 C Small General Service

Rate 4100 would be available to Small General Service customers who normally require less than 75 kW and do not qualify for other specific rates. Rate 4l00 would consist of:

• a generation service charge of 3.124/kWh for the first 200 kWh/month per kW of capacity plus 2.724/kWh for all additional kWh,



• a delivery service charge of: • 3.304/kWh for the first 200 kWh/month per kW of capacity plus 2.324/kWh for all

additional kWh, and • a fixed charge of $7.00/kW/month for the first 2 kW of capacity plus

$3.50/kW/month for all additional kW of capacity. The kW of capacity is the greatest of:

• the highest metered demand in the 12-month period including and ending with the billing period,

• the minimum demand as determined by application of the Terms and Conditions of Electric Service, or

• the rate minimum of 2 kW. The metered demand is the greater of the registered demand in kilowatts or 90% of the registered demand in kilovolt-amperes (B) Rate 4200 C Small General Time-of-Use Service

Rate 4200 is to be available to those customers who qualify for Rate 4100 and, in addition, have approved TOU metering. Rate 4200 would consist of:

• a generation service charge of 3.344/kWh for all kWh consumed on-peak and 2.724/kWh for all kWh consumed off-peak,

• a delivery service charge of: • 6.14/kWh for all kWh consumed on-peak and no charge for kWh consumed off-peak,

and • a fixed charge of $7.90/kW/month for the first 2 kW of capacity plus

$3.50/kW/month for all additional kW of capacity. The kW of capacity and the metered demand are the same as for Rate 4100. On-peak periods are 8 a.m. to 9 p.m., Monday to Friday. Off-peak periods are all other periods, including weekends. (C) Rate 4300 C Small General Temporary Service

Rate 4300 is to be available to customers who require Small General Service on a temporary or short-term basis for a maximum of 90 days per year. It would consist of:

• a generation service charge of 3.004/kWh for all kWh consumed, and • a delivery service charge of 17.004/kWh for all kWh consumed.

TransAlta does not invest in facilities required to supply electric service to customers on Rate 4300. The Rate 4300 customer is charged the cost of constructing and dismantling the facilities, less the value of any salvageable facilities.




MI

The MI submitted that TransAlta’s proposed Small General Service rates would move the revenue-to-cost ratio from 136% to 120% for this rate class. The MI also submitted that TransAlta’s reason for not reducing the revenue-to-cost ratio further down to 100% was the potential for rate shock, as moving the ratio to 100% would have affected other rate classes. However, the MI submitted that the amount of revenue generated from this rate class is small (compared to for example Large General Service) and would probably have a negligible “rate shock”, if any. Furthermore, the MI submitted that TransAlta is proposing selective changes such as the Large General Service–Large rate class which is proposed to receive a 2.6% reduction in rates notwithstanding a revenue-to-cost ratio on existing rates of 89% (95% on proposed TransAlta rates). The MI therefore submitted that, given that the Small General Service revenue-to-cost ratio has been significantly above unity for some time (136% on existing rates and 120% on TransAlta’s proposed rates), there is justification for a greater revenue-to-cost ratio decrease than that proposed by TransAlta. Board Findings

In Section 3(a), the Board directed TransAlta to design rates so that • the DISCO’s total charges related to Energy Supply, TA Billings and DISCO

Services are unbundled, with the revenue-to-cost ratio for each set at 100%. • the revenue-to-cost ratios for Energy Supply and TA Billings are each set at 100%

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


The Board also directed TransAlta to include a table showing the revenue-to-cost ratios for each cost source (Energy Supply, TA Billings and DISCO Services) for this rate class. The Board recognizes that the decrease to the rates for small general service rate class may have to be moderated to avoid significant adjustments to other rate classes. The Board also directs TransAlta to adjust the level of the TOU differential on its Energy Supply charges in the refiling to reflect the Board’s finding in Section 2(a)(1) of this Decision.



(9) Oil and Gas Service

(A) Rate 4400 C Unmetered Oil and Gas Service (Closed)

Proposed Rate 4400 is available to oil and natural gas field services and to water pumping services normally requiring less than 75 kilowatts. These services include pumping with related operations such as rectifiers, cathodic protection and radio transmitters. Unmetered accounts include services on Flat Rate Option D or services without TOU metering. TransAlta proposed to close Rate 4400 to new services, thereby requiring new oil and natural gas field services and water pumping services to take service on Rate 4500. Participants raised the issue of requiring existing oilfield accounts to move from the existing Rate 290 to the new Rate 4400 and eventually Rate 4500. Position of TransAlta

TransAlta submitted that 35,477 accounts are currently billed under the Small General Service Rate 290, of which approximately 2,500 are oilfield-related services. TransAlta explained that these oilfield-related services would be transferred to the proposed Rate 4500, Oil and Gas TOU Service, which was designed for Oilfield and Gas Services having TOU metering normally requiring less than 75 kW. Position of the Intervenors

IPPSA/SPPA

IPPSA/SPPA noted that under TransAlta’s current rates, small oilfield customers have had the choice of taking service under Small General Service (current Rate 290) or Oilfield/Water Pumping Service (current Rate 730). IPPSA/SPPA also noted that TransAlta’s proposal required all oilfield accounts, currently taking service on Rate 290, to move to TransAlta’s new Rate 4500, rather than allow customers the choice of moving to Rate 4100 Small General Service or Rate 4400. IPPSA/SPPA submitted that the impact of precluding small oil customers from taking service on existing Rate 290 (now updated to Rate 4100) should be evaluated. IPPSA/SPPA suggested a comparison of the cost of taking service on Rate 4100 to the cost incurred on the new rate from which each customer would be required to utilize. Further, IPPSA/SPPA submitted that, although TransAlta claimed that small oilfield customers would take service on Rate 4500, these customers would be required to take service under Rate 4400 until such time as they upgraded their secondary voltage equipment and TransAlta replaced their meters to TOU. Therefore, the rate impact should be compared between Rate 4100 and either Rate 4400 or Rate 4500. IPPSA/SPPA stated that customers currently on Rate 290 (now updated to Rate 4100) were typically low-load-factor customers as Rate 4100 had a higher energy-related charge, relative to fixed charges. Further, IPPSA/SPPA stated that TransAlta had not correctly reflected, in either Decision U99035 Page 86 10 August 1999


the COSS or the revenue analysis, that small oilfield customers, currently in Rate 290, would be required to take service on Rate 4400 until proper TOU meters were installed. IPPSA/SPPA submitted that, as a result, TransAlta’s shareholders would benefit by approximately $1.65 million at the expense of small oilfield customers. IPPSA/SPPA suggested that the benefit arose from low-load factor oilfield customers taking service on Rate 4400 because this rate has a larger fixed charge component relative to energy related charges. Consequently, IPPSA/SPPA submitted that the Board should require TransAlta to allow oilfield customers the ability to choose their service either under Rate 4100, 4400 or 4500 Board Findings

Current oilfield customers can choose to take service either under Rate 290 or Rate 730. The Board notes that TransAlta is proposing to replace Rate 290 with Rate 4100. The Board considers that these two rates are predominantly “energy rates”, as the energy charge component is more significant than the demand or fixed charge component. The Board understands that customers who selected Rate 290 were, typically, low-load factor customers. The Board notes that TransAlta is also proposing to replace Rate 730 with closed Rate 4400 or Rate 4500. The Board considers that Rates 730 and 4400 are predominantly “demand rates”, as the majority of the accounts using these rates are unmetered accounts. The Board notes that TransAlta is proposing that oilfield customers, currently under Rate 290 would migrate to new Rate 4500, rather than allowing them the option of utilizing Rate 4100, which is the updated version of Rate 290. The Board notes IPPSA/SPPA’s submission that oilfield customers currently in Rate 290 will be “parked” in Rate 4400 until such time as they upgrade their metering facilities and TransAlta installs TOU meters. The Board also notes that oilfield customers “parked” on Rate 4400 could pay higher charges, as Rate 4400 is predominantly a “demand” rate and oilfield customers previously using Rate 290 were the low-load factor customers. The Board finds that TransAlta has not clearly demonstrated that the costs to serve oilfield customers currently on Rate 290 are significantly different from the costs of serving other small general service customers under Rate 4100. If TransAlta maintains that the cost to serve oilfield customers is different than that for Rate 4100 customers, TransAlta should prepare a study demonstrating this at the time of its next general tariff application. Currently, the Board finds no compelling reason to require small oilfield customers currently using Rate 290 or Rate 730 to move to proposed Rate 4400 or 4500 without allowing them the choice of remaining in the proposed Small General Service, Rate 4100. The Board therefore directs TransAlta to make Rate 4100 available to oilfield customers currently on Rate 290 so that they are able to choose service under Rate 4100, 4400 or 4500.



(B) Rate 4500 C Oil and Gas Time-of-Use Service

Rate 4500 is to be available to oil and natural gas field services and to water pumping services normally requiring less than 75 kW. These services include pumping with related operations such as rectifiers, cathodic protection and radio transmitters. Rate 4500 is available to services that have TOU metering. TransAlta proposed that all new installations, connected on or after the approved effective date of this rate, should have the appropriate TOU metering. TransAlta proposed that existing services, with loads greater than 15 kW, have appropriate TOU metering. TransAlta stated that the customer would be responsible for installing, owning and maintaining all wiring on the customer’s side of the meter including a suitable service entrance and meter socket or enclosure. TransAlta would invest up to $2,000 for any retrofit of the customer’s facilities required to provide an appropriate meter connection. TransAlta would then supply, install, own and maintain the TOU meter. Participants raised the issues of (i) appropriate allocation of oilfield costs (ii) required metering and (iii) metering totalization with respect to Rate 4500. (i) Appropriate Allocation of Oilfield Costs

The oilfield customers indicated that services were built, upgraded and charged to them. These services provided additional benefits to the rural customers to whom no costs were allocated. TransAlta proposed that all oilfield customers be served as a separate oilfield class. The oilfield customers requested that TransAlta prepare a customer classification study to justify the need for oil industry specific class. The FIRM Customers objected to the request for such a study to separate the oilfield rate class. Position of the Intervenors

IPPSA/SPPA

IPPSA/SPPA indicated that oilfield customers were the fastest growing customer class. But, as rural based assets are put in place to serve oilfield facilities, other adjacent rural customers also benefited from an improved system and, in many cases, enjoyed the upgrade to three phase service. IPPSA/SPPA suggested this direct benefit had been conferred on rural customers who would not otherwise receive the increased level of service and the upgraded three-phase service. However, IPPSA/SPPA stated that the costs of these facilities were allocated to oilfield customers, even though farm customers were benefiting from these facilities. Therefore, IPPSA/SPPA requested that the Board direct TransAlta to prepare a “customer classification study” and file such a study in conjunction with the next Phase II process. IPPSA/SPPA advocated that all customer classes should pay their fair share of costs and submitted that if the study, recommended by IPPSA/SPPA, showed that oilfield customers should be allocated more costs than was currently the case, then oilfield customers should pay more. As well, IPPSA/SPPA advocated that if the study showed that other rural customers



should be allocated more costs than was currently the case, those rural customers should also pay more. In support of its request, IPPSA/SPPA submitted that TransAlta’s proposal to move Rate 290 oilfield accounts to Rate 4500 was symptomatic of the problems that arose from having a separate oilfield customer class. IPPSA/SPPA indicated TransAlta’s testimony showed that:

• the generation charges for small general service and oilfield accounts were similar, • 98.5% of customers in the oilfield class were outside corporate boundaries and could be

classified as “rural”, • 30% of customers in the general service class were outside corporate boundaries and

could also be classified as “rural,” and • the classification of small general service customers into “rural” and “urban” had merit.

Therefore, IPPSA/SPPA submitted that TransAlta’s attempt to move Rate 290 oilfield customers to Rate 4500 was to transfer some of the 30% rural accounts from an “urban” to a “rural” type rate, specifically Rate 4500. IPPSA/SPPA submitted, in response to arguments filed by the FIRM Customers, that IPPSA/SPPA did not advocate the creation of two major distribution categories, nor did IPPSA/SPPA suggest that costs should be rolled up across a larger customer base. IPPSA/SPPA suggested that the need for an industry specific customer class should be reviewed. In particular, IPPSA/SPPA indicated that oilfield facilities are not the only accounts that were “rural”, as many general services and all larger agricultural operations shared the same remoteness and load characteristics as oilfield accounts. IPPSA/SPPA submitted that the cost to serve these types of loads may generally be the same and IPPSA/SPPA was only requesting that TransAlta expend the effort to find out. FIRM Customers

The FIRM Customers submitted that IPPSA/SPPA’s request, for TransAlta to provide a detailed study on the need for a separate oilfield customer class, was based on the view that there was no need for a customer rate class specific to an industry. Instead, the FIRM Customers submitted IPPSA/SPPA would prefer a rural/urban split as IPPSA/SPPA believed a split would be “closer to cost causation.” The FIRM Customers also submitted that IPPSA/SPPA advocated an averaging of all costs, currently identified as being caused by specific rate classes, into two major distribution categories, namely rural and urban. The FIRM Customers suggested that IPPSA/SPPA was ignoring the fact that facilities were put in place to serve customers developing oilfields and that those costs were also incurred for other customers such as farm and general service and thus allocated specifically to those classes in TransAlta’s COSS. The FIRM Customers submitted that bundling these costs up to a higher level did not improve the allocation of costs on the basis of cost causation. Furthermore, the



FIRM Customers submitted that costs caused by oilfield customers should be allocated to the oilfield class. The FIRM Customers also submitted that, if oilfield customers wanted rates designed consistent with small commercial or industrial rates, then a separate rate design should be initiated. The FIRM Customers stated that a rate design issue should not be used as the basis for rolling up costs to be averaged across a larger customer base. The FIRM Customers submitted that rural/non-rural high level averaging was an issue for several years in AE’s Phase II proceedings. Further, the FIRM Customers noted AE’s position in its current Phase II proceeding:

Over the last number of years, significant growth in the oilfield and industrial rate classes has resulted in a large increase in distribution related capital expenditures. During this same period, the farm rate class has had virtually no growth. However, being part of the “rural” class of customers in the COSS, farm customers have been allocated a share of the larger increase in distribution capital built to serve the oilfield and industrial classes that have grown at a much faster rate. These capital expenditures were not caused by growth in, nor made use of by the Farm rate class. As a result APL is proposing a lower revenue to cost ratio as compared to the 1993 Phase II application to reflect that the high load growth in the industrial and oilfield customer classes has resulted in a disproportionate share of distribution capital assets being allocated to the company farm rate class. 29

Therefore, the FIRM Customers submitted that the Board should not grant IPPSA/SPPA’s request for TransAlta to study the need for a separate oilfield rate class. The FIRM Customers stated that there were differences in the annual rates of growth between customer rate classes and consequently, averaging costs at a higher level in the distribution system would result in unfair cost allocations to rate classes experiencing slower growth rates. Further, the FIRM Customers submitted that, if the Board was to consider aggregating at the rural/urban level, TransAlta should necessarily review its investment level for those rate classes showing higher than average growth. The FIRM Customers indicated a review would be required to ensure existing customers did not end up paying for that growth. The FIRM Customers submitted that IPPSA/SPPA’s proposed method was a complicated way of trying to achieve fairness between rate classes and, therefore, recommended that TransAlta’s current, and long established, method of accounting for distribution rate base additions by rate class when caused by that rate class be continued. Board Findings

The Board notes IPPSA/SPPA suggested that distribution facilities built to serve oilfield customers also benefit farm customers, questioned the need for an industry specific customer class, and proposed that TransAlta should conduct a study to investigate commonalties between


29 BR.APL-14


oilfield, general service, and farm customers – referred to as “rural” customers. However, IPPSA/SPPA did not advocate bundling all rural customers into one larger customer class. The Board notes IPPSA/SPPA’s suggestion that this issue is about fairness; i.e., whether or not farm customers who benefit from distribution facilities installed to serve oilfield customers should share a portion of the cost of these facilities. TransAlta proposed that the cost of facilities installed to serve oilfield customers should be allocated to the oilfield class and IPPSA/SPPA’s recommended study is to determine whether or not the allocation of the cost of these facilities is fair. The Board considers that TransAlta’s proposed allocation of distribution rate base additions between rate classes is consistent with both the principle of cost causation and future unbundling. The Board considers that the identifiable costs of facilities installed to supply oilfield customers should be assigned to oilfield customers. The Board notes IPPSA/SPPA’s contention that adjacent rural customers also benefit from the improved system that arises from the growth of the oilfield customers. However, the Board considers such benefits to be incidental and has no evidence that the farm customers who received benefits either required them or would desire them if they knew extra charges would arise. In establishing rate classes, the goal must be to group together customers with similar cost of service characteristics to the greatest extent practicable. However, there will almost always be some variation in cost causation amongst customers in a rate class. While the Board accepts that additional facilities were required to serve oilfield customers and that these customers should therefore bear the costs at this time, the Board considers that these claims should be substantiated by further study. The Board considers that such a study would determine whether or not the cost of oilfield facilities should be allocated to other customer groups because of benefits they receive. The Board therefore directs TransAlta to include a study, with its PDT filing, that examines the commonalities and benefits shared between oilfield, general service and farm customers and recommends an appropriate rate class or classes for these customers based on their cost of service characteristics. For the purposes of this Decision, the Board accepts TransAlta’s proposed oilfield customer classification and the allocation of costs to this rate class as conditioned by the Board’s general findings from the Rate Design section. In Section 3(a), the Board directed TransAlta to design rates so that:


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

• the overall increase in revenue over that collected from existing rates is kept at less than 10% for every class, by adjusting as required the “residual” DISCO Services



amounts to be recovered from customer classes. (The Board notes that individual customers may see more than a 10% increase if their usage characteristics warrant.)

The Board also directed TransAlta to include a table showing the revenue-to-cost ratios for each cost source (Energy Supply, TA Billings and DISCO Services) for this rate class. (ii) Required Metering

TransAlta proposed that all oilfield services be switched to Rate 4500 and metered within five years. The oilfield customers suggested that switching to Rate 4500 with required metering should be at the discretion of the customer. Position of TransAlta

TransAlta submitted that Rate 4500 was intended to prepare customers for customer choice, to take advantage of lower bills through energy conservation, and to manage electricity costs by shifting to lower cost time periods. TransAlta indicated that unmetered service was not consistent with the New World and therefore proposed to begin metering oilfield services to promote customer choice. TransAlta further submitted that, when customers have a choice as to who will supply them with generation, the retailer will need to know how much energy is required and the profile of that energy consumption in order to procure that energy and sell it to the oilfield customer. TransAlta proposed that all oilfield services be metered and planned to phase in metering for oilfield customers within five years. TransAlta proposed that existing services greater than 15 kW be required to install appropriate TOU metering. TransAlta also proposed to supply the meter and to invest up to $2,000 for the customer side of the meter facilities for these services. TransAlta indicated that, out of 12,061 unmetered accounts currently under Rate 73X; there were 3,219 unmetered accounts above 15 kW requiring TOU meters under Rate 4500. TransAlta submitted that the Oilfield rate class was the only rate class remaining where unmetered service was prevalent and energy consumption was not accurately predictable. TransAlta submitted that oilfield services should begin metering to obtain such basic information as energy consumption and demand to facilitate customer choice and retail competition, and to avoid undue discrimination between customers in this class. Furthermore, TransAlta indicated that meters would enable customers to lower their bills through energy conservation and to manage their electricity costs by shifting usage to lower cost time periods. In response to the IPPSA/SPPA suggestion, that meter reading frequency for Rate 4500 accounts should be set uniformly at two months, TransAlta submitted that so rigid a standard would be inappropriate especially when some services may be remote and inaccessible at times. Therefore, TransAlta recommended that meter reading schedules be left to TransAlta’s discretion.




IPPSA/SPPA

IPPSA/SPPA took exception to TransAlta’s proposition that retail competition would require metered energy consumption. IPPSA/SPPA submitted that, when retail competition is implemented in the year 2001, some retailers might be content to provide service to an oilfield customer based on estimated consumption. IPPSA/SPPA indicated that if a retailer required a higher price from a customer to absorb any risk associated with unmetered accounts, then the higher price would signal the customer to upgrade the meter. IPPSA/SPPA also noted that retail competition would not be implemented in 1999 or 2000, the time period over which the proposed rates are to be in effect. Therefore, IPPSA/SPPA submitted that requiring customers to install meters now was premature. In addition, IPPSA/SPPA submitted that the cost of meters capable of providing hourly data would likely continue to decrease as more jurisdictions implemented customer choice thus making the supply and installation of meters less expensive in the future. IPPSA/SPPA submitted that TransAlta had many unmetered accounts in several customer classes and that distribution rates, that have been based on connected or estimated demands and load factors, could continue to exist. Therefore, IPPSA/SPPA recommended that customers be given the choice to upgrade their meters if warranted when the details regarding retail competition and direct access are known. IPPSA/SPPA concluded that TransAlta’s proposed changes were neither required nor prudent at this time. IPPSA/SPPA submitted that TransAlta recognized the rate shock the proposed Rate 4500 would have on high load factor customers and therefore, re-designed the rate to minimize rate shock. The first design of Rate 4500 included an energy component in the Delivery Service Charge of 2.024/kWh for all on-peak consumption. IPPSA/SPPA suggested this rate design would have resulted in large price changes to individual oilfield accounts; for example, for 20% load factor accounts, rate decreases of 32% to 36% could be expected and for 80% load factor accounts, rate increases of 28% to 31% could be expected. IPPSA/SPPA also submitted that TransAlta’s suggestion that since most oilfield customers had many accounts, any one customer would not see a significant overall increase as increases in one account would be compensated by decreases in another account. However, IPPSA/SPPA submitted that this assumption was inaccurate as many oilfield customers have embraced high load factor pumping technologies with the expectation that rate increases for large load sizes would be outweighed by rate decreases for smaller load sizes. IPPSA/SPPA noted that TransAlta revised Rate 4500 on 7 October 1998 and removed the delivery energy charge and replaced it with higher demand charges. IPPSA/SPPA indicated that the second proposed design reduced the rate decreases and increases for low and high load factor accounts respectively. However, for the average 80% load factor accounts, IPPSA/SPPA suggested a rate increase of over 20% was still expected and, since TransAlta’s proposal



contemplated that only the larger loads (above 15 kW), which tend to have the higher load factors, should be moved to Rate 4500, the oilfield customer class would see a price increase. IPPSA/SPPA submitted that TransAlta’s proposed change would benefit TransAlta’s shareholders at the expense of oilfield customers and, therefore suggested that TransAlta should not force metering upgrades and allow existing Rate 730 accounts to move to Rate 4400, not to Rate 4500. IPPSA/SPPA recommended that all Rate 4400 customers be “grandfathered” and not be required to switch to proposed Rate 4500. However, IPPSA/SPPA also recommended that, for new customers and for customers electing to upgrade the meter, service should be provided on Rate 4500. IPPSA/SPPA indicated that this approach was consistent with the practices of AE and SaskPower regarding the metering of new and upgraded oilfield services. In addition, IPPSA/SPPA submitted that the meter read frequency for Rate 4500 accounts should be set uniformly, every two months, as bimonthly meter reading would balance the need for appropriate metering information with the cost of meter reads. IPPSA/SPPA took the position that meter upgrades were not required at this time, but submitted that should the Board approve TransAlta’s proposal requiring oilfield customers to upgrade meters, the following issues should be addressed to ensure implementation did not result in undue discrimination against oilfield customers:

• IPPSA/SPPA recommended a size limit of 25 kW, rather than TransAlta’s proposed 15 kW. The larger size would reduce the number of accounts required to install TOU meters from 3,000 to about 1,500.

• IPPSA/SPPA recommended TransAlta change its existing policy of not allowing

customers to attach a metering support on TransAlta’s poles. IPPSA/SPPA suggested forcing customers to use a separate support structure would significantly increase the cost of meter conversions. IPPSA/SPPA indicated that TransAlta agreed to allow customers to attach to their poles as long as safety and electrical code issues were observed and requested the Board include this provision for any metering upgrades.

• IPPSA/SPPA submitted that TransAlta’s maximum investment of $2,000 meant that

TransAlta would not have control over how costs were incurred and would be investing in work preformed by others. Further, IPPSA/SPPA submitted TransAlta had not offered evidence as to the appropriateness of the $2,000 per facility investment level. Therefore, IPPSA/SPPA suggested that an average cost of $1,572 for the majority of the unmetered accounts was appropriate.

• IPPSA/SPPA submitted that the cost of metering, if required, was a result of industry

restructuring and therefore the costs should be borne by all customers. As well, if metering upgrades were required for other customer classes, as a result of restructuring, then all customers should share the costs. Therefore, IPPSA/SPPA did



not agree with TransAlta’s proposal that the cost of meter conversions should be included in distribution property and charged back to oilfield customers. IPPSA/SPPA indicated agreement with the FIRM Customers that if a customer sees a potential benefit, they should bear the cost. However, IPPSA/SPPA submitted that if metering upgrades were imposed upon the customer, for no other reason than to accommodate TransAlta’s perception of the future, then these costs resulted solely from industry restructuring and should be borne by all customers.

• IPPSA/SPPA recommended that in the design of Rate 4500, the billing determinants

used should be made equal to the rate 4400 determinants. In particular, TransAlta proposed, in rebuttal evidence, to use a conversion factor of 98.35%. However, IPPSA/SPPA recommended a higher conversion factor since IPPSA/SPPA considered AE data, which suggested a 99.47% conversion factor for pumpjack accounts, to be a more indicative factor. IPPSA/SPPA indicated that if AE data were used, the conversion factor would be 100.3%. Therefore, IPPSA/SPPA recommended, in the absence of other evidence, a conversion factor of 100% for the design of Rate 4500 billing determinants. IPPSA/SPPA indicated that TransAlta claimed that using a 100% conversion factor, rather than TransAlta’s proposed 98.35%, would result in reduced revenues of approximately $935,000. However, IPPSA/SPPA submitted that TransAlta’s assessment of reduced revenue assumed that all Rate 4400 customers would be moved to Rate 4500 and did not account for TransAlta’s latest proposal that only those accounts over 15 kW would be moved over a yet to be determined implementation period. Therefore, IPPSA/SPPA submitted that the difference between TransAlta’s and IPPSA/SPPA’s proposed conversion factors was more likely in the $100,000 range for 1999. IPPSA/SPPA reiterated that this issue could be avoided if IPPSA/SPPA’s recommendation of not allowing TransAlta to force metering upgrades was accepted. IPPSA/SPPA recommended new accounts be served on Rate 4500.

IPCAA

IPCAA stated that, by letter dated 7 October 1998, TransAlta had amended the Application, to minimize the overall cost of installing meters, by requiring the largest unmetered oil and gas services to be metered. Although IPCAA agreed with the amendment, they noted that the tariff Rate 4400 was still “closed” and that TransAlta had not offered any explanations why oil and gas service customers required TOU rates. IPCAA submitted that if TransAlta needed the information, then TransAlta should be responsible for the costs of supplying and installing TOU meters, not the customers. FIRM Customers

The FIRM Customers opposed IPPSA/SPPA’s proposal to have all customers share in the costs of meter conversion. The FIRM Customers submitted that if the Board accepts IPPSA/SPPA’s position that meter upgrades were required and the capital costs should be borne equally by all Decision U99035 Page 95 10 August 1999


customers, then, to the extent a customer was able to gain benefits from direct access, that customer should pay the costs. The FIRM Customers advocated that the costs should not be shifted to other ratepayers, including those customers who do not, or cannot, choose direct access. The FIRM Customers reiterated that small customers who did not need interval meters should not be required to share the costs. Although the FIRM Customers support customers being given the choice to upgrade their meters once they know the options available, customers who receive the benefit from upgrading their meters should bear the costs. Board Findings

The Board notes TransAlta’s submission that metering oilfield services to obtain basic information and to facilitate upcoming customer choice and retail competition should begin in 1999. The Board also notes TransAlta’s view that meters would enable customers to lower their bills through energy conservation and to manage their electricity costs by shifting usage to lower cost time periods. The Board considers that these two points have merit, but they are not sufficiently strong to persuade the Board to approve a rate that would force some customers to upgrade their metering facilities in preparation for retail competition in the year 2001. Instead, the Board agrees with IPPSA/SPPA’s submission that when retail competition is implemented in the year 2001, some retailers may choose to provide service to oilfield customers based on estimated consumption, other retailers may choose to provide service based on standard meters, and yet others based on TOU meters. The Board also agrees with IPPSA/SPPA’s submission that, by the time retail competition is implemented in 2001, the cost of electronic TOU meters may be lower as these types of meters become more widely used in North America. The Board therefore finds that customers should be given the choice as to whether or not to install or upgrade meters, rather than being forced to install/upgrade meters now. Also, in line with this finding, the Board is of the view that new oilfield customers should have the choice of taking service under either Rate 4400 or Rate 4500. The Board notes that Rate 4400 is a demand based rate and considers 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 smaller customers. The Board therefore directs TransAlta to design an additional rate for Oil and Gas Service, a metered rate similar to Rate 4500 but without the TOU component. Providing this choice will be consistent with other rates proposed by TransAlta, such as residential rates, where new customers can choose either the standard or the TOU service metered service. The Board also directs TransAlta to adjust the level of the TOU differential in its Energy Supply charges in the refiling to reflect the Board’s finding in Section 2(a)(1) of this Decision. The Board directs TransAlta to include this new rate offering at the time of its refiling and to amend its proposed Rate 4400 to remove its designation as a closed rate.



The Board does not agree with IPPSA/SPPA’s submission that the costs of new or upgraded meters should be paid by all customers. The Board considers that, as customers have the choice of installing and/or upgrading meters at their convenience, the cost of supplying and installing the meters should be borne by the customers requesting the service. The Board finds that the frequency of meter reading should be left to TransAlta’s discretion. The Board has not accepted TransAlta’s proposal to meter all customers within five years, therefore it will not address findings on the alternatives suggested by IPPSA/SPPA. (iii) Meter Totalization

Meter totalization refers to the installation of a single meter for collective oilfield facilities in order to reduce the total delivery charge when compared to multiple meters/accounts. The oilfield customers advocated this approach. TransAlta stated that the changes made to service minimums and the introduction of Rate 4500 providing a separate generation service charge based on energy, effectively allowed totalization to occur for the generation component. Position of the Intervenors

IPPSA/SPPA

IPPSA/SPPA explained that, currently, oilfield customers may have several meters/accounts that were installed as a result of the progressive development of their oilfield pumping and gathering facilities through time and that each account had its own demand charges. Therefore, IPPSA/SPPA proposed “totalization”, i.e., the installation of one single meter for the entire oilfield facilities and indicated that one single meter would reduce the total delivery charge (because of load diversity) when compared to multiple meters/accounts. Recognizing that totalization would reduce the revenues collected by the utility, IPPSA/SPPA proposed a Totalization Rate Rider (TRR) applicable to customers on Rate 6100, 6200, 6300 and 6800. The TRR would allow TransAlta to recover the reduced delivery charges resulting from installation of totalized metering. IPPSA/SPPA submitted that TransAlta had admitted that totalization could offer benefits to customers and that the prospects of having customers build redundant facilities was not in the best interests of TransAlta and its customers. However, IPPSA/SPPA submitted that TransAlta acknowledged it had been unsuccessful in developing a totalization tariffCprimarily because TransAlta would find it impossible to develop a broadly applied tariff without introducing winners and losers from a cost recovery perspective. Therefore, IPPSA/SPPA proposed that, to ensure that wires-related revenue did not decrease as a result of totalization, a case-by-case approach to determine revenue-neutral post-totalization Decision U99035 Page 97 10 August 1999


wires rates be conducted for each project. IPPSA/SPPA indicated that TransAlta’s primary objection with the case-by-case approach seemed to be related to administration. However, IPPSA/SPPA noted that TransAlta proposed a case-by-case approach for generator interconnection and argued that this approach was reasonable because there have been very few generator interconnection projects in the past. IPPSA/SPPA suggested that TransAlta highlighted the burden that case-by-case totalization calculations would pose by drawing a comparison between the small number of generation interconnection projects with the large number of oilfield services. However, IPPSA/SPPA submitted that this comparison was meaningless. IPPSA/SPPA submitted that TransAlta did not offer evidence to support the supposition that case-by-case totalization projects would pose an administrative burden. IPPSA/SPPA stated TransAlta did not identify any history of totalization projects, and did not estimate the number of potential totalization projects that could exist with TransAlta’s thousands of individual oilfield services. IPPSA/SPPA also stated that TransAlta did not account for the benefits which IPPSA/SPPA believed would flow from allowing totalization; i.e. reduced facilities, increased power efficiency, increased oilfield production and operational optimization. IPPSA/SPPA submitted that TransAlta attempted to argue that, with the proposed changes to Rate 4500, totalization would already occur for the generation component. IPPSA/SPPA submitted that, while this rate design was an improvement over current rates offered to the oilfield class, IPPSA/SPPA did not agree that the design adequately reflected the generation costs. IPPSA/SPPA stated that additional generation costs could be avoided if a group of oilfield facilities were allowed to totalize and rationalize operations from an energy use standpoint. IPPSA/SPPA did not agree with the design of Rate 4500, which recovered all generation costs through energy charges. Furthermore, IPPSA/SPPA disagreed that the energy charges proposed by TransAlta reflected market on-peak and off-peak energy. IPPSA/SPPA submitted that, in the end, the proposed Rate 4500 under-compensated producers for the cost reductions they could obtain through totalization. Moreover, IPPSA/SPPA submitted that TransAlta’s design for Rate 4500 did not separate the Transmission and Distribution components and, as a result, did not provide incentives to producers for reducing point-of-delivery coincident demand in order to reduce transmission charges. IPPSA/SPPA submitted that, in addition to the benefits from production optimization, totalization would improve the economics of on-site flare gas generation and would result in greater competition for generation services. IPPSA/SPPA requested the approval of a rider to allow customers to approach TransAlta and negotiate on a case-by-case basis. IPPSA/SPPA submitted the approval of this rider was required to allow customers to make their case and establish that the “totalization” request could be accomplished on a basis that keeps other customers whole.



IPPSA/SPPA submitted that if the administrative burden associated with re-calculating wires charges on a case-by-case basis became too great, a charge could be introduced at a later date when sufficient information existed to quantify the incremental administrative costs associated with totalization. In this regard, IPPSA/SPPA indicated that TransAlta had been able and was willing to administer the TA’s GOS rate and allowed customers to receive opportunity service in appropriate cases. IPPSA/SPPA submitted that TransAlta’s administrative “attention” required to conduct economic assessments associated with GOS service clearly outweighed that which might be required in cases of totalization. IPPSA/SPPA submitted that, in the end, TransAlta agreed that totalization, through a negotiated approach as proposed by IPPSA/SPPA, could work. IPPSA/SPPA requested that oilfield customers be allowed an opportunity to make a negotiated process work by having IPPSA/SPPA’s proposed TRR, as set out in its evidence approved. IPPSA/SPPA clarified that the proposed case-by-case approach to determine revenue-neutral wires rates for each project would ensure that totalization would not discriminate against individual services and put upward pressure on rates. Further, IPPSA/SPPA submitted that TransAlta had agreed that meter totalization, through a negotiated approach, as proposed by IPPSA/SPPA, could work. IPPSA/SPPA disagreed with TransAlta’s suggestion that totalization would discriminate against individual services and put upward pressure on rates. IPPSA/SPPA submitted that the discrimination against oilfield operations, which happened to be geographically separated due to the nature of the resource they produce, lead IPPSA/SPPA to recommend a TRR. IPPSA/SPPA also submitted that there was no evidence to suggest that the proposed tariff would result in inequitable rates over time and would become an administrative burden. On the contrary, IPPSA/SPPA’s proposal was intended to ensure rates remained equitable in a manner that would minimize administrative burdens and regulatory costs over possible alternatives that oilfield customers may pursue. In response to the FIRM Customers’ concerns, IPPSA/SPPA replied that the proposal was intended to ensure no other customer was disadvantaged, including other oilfield customers. To the extent that some costs could shift to other customers, IPPSA/SPPA submitted they would likely be shifted to others within the same oilfield customer class. IPPSA/SPPA suggested there was no evidence that IPPSA/SPPA’s proposal would ultimately affect other customers as the FIRM Customers implied. IPPSA/SPPA concluded that the proposed TRR would only provide a framework for oilfield customers to negotiate with TransAlta for the totalization of oilfields where operational efficiencies could be gained. Further, IPPSA/SPPA indicated that there were sufficient checks and balances in the regulatory process to ensure that the proposed TRR will not adversely impact other customers. Decision U99035 Page 99 10 August 1999


FIRM Customers

The FIRM Customers submitted that TransAlta’s rebuttal evidence indicated the design of Rate 4500 resulted in totalization for the generation component, but the implementation of the IPPSA/SPPA proposal would require a primary voltage level meter plus a case by case negotiation of a new delivery service charge. The FIRM Customers reiterated TransAlta’s position that the proposed tariff would not result in fair and equitable rates over time and would become an administrative burden. The FIRM Customers stated that, in addition, totalization appeared to result in a revenue decrease. The FIRM Customers expressed concern that, to the extent there may be a reduction in revenues from the oilfield customers, there could potentially be an impact on other customers. As IPPSA/SPPA’s evidence indicated, their recommendations should “not benefit or disadvantage other customers.” However, the FIRM Customers suggested the revenue impact of IPPSA/SPPA’s proposal would ultimately affect other customers, except in the unlikely event the revenue shortfall was somehow retained within the Oilfield rate class. The FIRM Customers submitted that the evidence, presented by TransAlta on this issue, indicated problems with the IPPSA/SPPA proposal and to rectify the problems, costs would have to be incurred. Further, the potential revenue reduction from totalization was also of concern to the FIRM Customers. While the FIRM Customers did not oppose IPPSA/SPPA’s request for totalization of oilfield loads on the basis such totalization would not disadvantage other customer rate classes it indicated that the proposal appeared to have some inherent problems and associated costs. In the FIRM Customers’ view, if any costs were incurred in the future, then these costs should be borne by the customers in the Oilfield rate class and should not be split amongst all other consumers. Position of TransAlta

TransAlta stated in its Terms and Conditions, Clause 4, that each point of delivery is billed as a separate service; subsequently, TransAlta had designed their rates on that basis. TransAlta submitted that implementing IPPSA/SPPA’s proposal would require a primary voltage level meter plus a case by case negotiation of a new Delivery Service Charge. TransAlta asserted that totalization over an area would create a higher effective level of investment for aggregated services. TransAlta submitted that totalization would therefore discriminate against individual services and put upward pressure on rates. TransAlta indicated that investment in new load would be difficult to determine since new load may not correspond to the increased demand at the meter. TransAlta, therefore, submitted the proposed tariff would not result in fair and equitable rates over time and would become an administrative burden.



TransAlta stated that, where a customer could legally, technically, and economically totalize two or more loads, TransAlta would work with the customer to achieve a mutually beneficial solution that avoids bypass. TransAlta submitted that IPPSA/SPPA’s recommended TRR would result in a number of individual services being treated as one service. TransAlta further submitted that totalization would benefit customers who can totalize but could affect other customers as the loss of revenue due to totalization would have to be recovered from other customers within the class or other classes. Although there was discussion of the totalization issue during the hearing, TransAlta submitted that the record did not demonstrate that totalization was an urgent matter, nor would actually provide benefit to the system as a whole. Therefore, in the absence of evidence for benefit to the system and for the urgency to customers who could take advantage of a totalization rider, TransAlta recommended that the proposed IPPSA/SPPA TRR not be approved. Board Findings

The Board considers approval of IPPSA/SPPA’s proposed TRR would give oilfield customers, who currently may have several accounts/meters servicing their oilfield facilities, the right to approach TransAlta and negotiate a rate resulting in a single account/meter servicing collective oilfield facilities. The Board notes that under the proposal a single account/meter would translate into oilfield customers paying less demand/fixed transmission and distribution charges, but they would pay an additional negotiated rate-rider to TransAlta such that the utility would recover the same fixed/demand charges as without totalization. Such a TRR might encourage oilfield customers to modify their pattern of consumption of electric power towards a more efficient use. At the same time, the TRR would keep the utility whole, as the rider would compensate the utility for the decreased demand/fixed charges due to totalization. The Board, however, is concerned that approval of the proposed TRR, which requires case-by-case negotiation between the utility and oilfield customer, may impose an administrative burden on TransAlta, because of the number of oilfield accounts that may be totalized. Since the Board has accepted generation charges which are purely energy based, generation costs are effectively totalized and any saving arising from totalization would be from TA Billings and DISCO Services components only. The Board further notes that with its direction in the findings regarding Required Metering to implement a metered rate without the TOU option, customers are able to totalize their Energy Supply costs without incurring the cost of a TOU meter.



Accordingly, the Board will not direct TransAlta to provide for the totalization of meters and a TRR as requested by IPPSA/SPPA. (10) Large General Service

TransAlta proposed to eliminate Rates 760, 770, and 790 and replace them with the following rates: 6100–General Service; 6200–General Time of Use Service; 6300–Large General Time-of-Use Service; and 6400–Transmission Service. Certain issues raised with respect to these rates, such as unbundling and time of use, are generic in nature and have been addressed in Section 3(a). Only rate specific issues are addressed in the following sections. (A) Rate 6100 C General Service

Rate 6100 is to be available to General Service customers with a normal billing capacity of less than 2,000 kW, who do not have time of use metering and do not qualify for other specific rates. The rate has been unbundled into a Generation service charge which is 100% energy based and a Delivery service charge which is primarily demand based. (B) Rate 6200 C General Time-of-Use Service

Rate 6200 is to be available to General Service customers with a normal billing capacity of less than 2000 kW, who have approved TOU metering and do not qualify for other specific rates. The rate has been unbundled into a Generation service charge which is 100% energy based and a Delivery service charge which is primarily demand based. Energy charges for the rate are proposed to vary according to on-peak, shoulder, and off-peak pricing. Energy charges are also proposed to vary seasonally with a pricing schedule for each of the winter and summer seasons. (C) Rate 6300 C Large General Time-Of-Use Service

Rate 6300 is to be available to Large General Service customers with a normal billing capacity greater than or equal to 2000 kW and less than 10,000 kW. The rate has been unbundled into a Generation service charge which is 100% energy based and a Delivery service charge which is primarily demand based. Energy charges for the rate are proposed to vary according to on-peak, shoulder, and off-peak pricing. Energy charges are also proposed to vary seasonally with a pricing schedule for each of the winter and summer seasons. (D) Rate 6400 C Transmission Service

Transmission Time of Use Rate 6400 is time of use differentiated and is designed for customers with loads of 10,000 kW and over who are generally served directly from the transmission system. The rate is unbundled into a Generation Service Charge (100% energy based) and a Delivery Service Charge (100% demand based). Energy charges for the rate are proposed to vary according to on-peak, shoulder, and off-peak pricing. Energy charges are also proposed to vary seasonally with a pricing schedule for each of the winter and summer seasons. Decision U99035 Page 102 10 August 1999



IPCAA

Only one rate specific issue was raised with respect to Rate 6400. In its argument IPCAA commented upon TransAlta’s proposal to limit Rate 6400 to customers with loads of 10 MW or more. IPCAA stated that it could see no reason why smaller loads should be precluded from taking service at the transmission level. IPCAA maintained that even if all existing transmission level customers were above this size, new customers of any size should have the choice available. Position of TransAlta

TransAlta stated that the design of rates considered the economies of scale of serving large customers and was not based on voltage level, geographic location, or other parameters. The design of Rate 6400 was determined for customers who are 10,000 kW or larger and the rate minimum for Rate 6400 is, therefore, 10,000 kW. TransAlta also explained that it considered load size, not voltage level, to be the appropriate basis in passing through economies of scale to a customer, and that large customers are generally less costly to serve on a per unit basis, which is reflected through different rate classes and declining block prices. TransAlta recommended that the Board continue its practice of segregating rate classes by customer size, not voltage level, for both cost of service and rate design purposes. Board Findings

The Board notes that the only issue raised respecting Rates 6200 and 6300 related to the issue of TOU. The Board’s determinations on TOU are made in Section 2(a) of this Decision. With respect to the recommendation that service from the transmission system not be restricted to customers with loads of 10,000 kW or greater, the Board notes TransAlta’s comment that Rate 6400 reflected the economies of scale of large customers. The Board considers the argument of TransAlta is reasonable and accepts the limit on the availability of Rate 6400 to customers with a 10,000 kW minimum. In Section 3(a), the Board directed TransAlta to design rates so that

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

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




The Board also directed TransAlta to include a table showing the revenue-to-cost ratios for each cost source (Energy Supply, TA Billings and DISCO Services) for this rate class. The Board also directs TransAlta to adjust the level of the TOU differential in its Energy Supply charges in the refiling to reflect the Board’s finding in Section 2(a)(1) of this Decision. (11) Temporary Energy Service C Rate 6600

This rate is to be available to general service customers and is fully interruptible. TransAlta will negotiate an individual rate with customers who apply for temporary energy. Temporary energy is surplus energy that is sold at a discount from standard transmission and distribution embedded rates. The discount exists because the sale would not occur if the load were subject to standard rates. The net revenue from this rate is allocated back to firm rate customers as a credit to the cost of service of these customer classes. Position of the Intervenors

Amoco

Amoco submitted that Rate 6600 should consist of only two components—the pool price and the charges of the TA. It should not include any additional contribution to fixed costs paid by TransAlta DISCO. Amoco maintained that recovery of any allowance for fixed costs is inconsistent with the development of an open market, stating that any such contribution is antithetical to the market concept. Amoco noted that power in the new system is purchased through the pool and any contribution to fixed costs will not go to the generator incurring those costs but rather to the firm customers of TransAlta. Transmission costs incurred by the TA are recovered from temporary energy customers through the application of the TA Grid Opportunity Service (GOS) tariff on a flow through basis. No facilities were built for temporary energy customers because they did not need to be built. TA costs are recovered by the TA tariff and should not be over recovered by additional contribution from temporary energy customers. Amoco also noted that, in the TransAlta Provost application dealing with the extension of a transmission line to the Saskatchewan border to service a load in Saskatchewan, no contribution to fixed costs was sought. Amoco submitted that temporary energy customers within Alberta should not be treated more harshly than export customers. Amoco also stated that should the concept of such a contribution be retained it should be negotiable to provide an incentive for temporary energy sales to occur. Amoco disputed TransAlta’s assertion that no evidence has been filed proposing changes to the rate. Amoco stated that its counsel had adduced evidence through cross-examination of TransAlta’s panel. Amoco also stated that TransAlta said nothing to justify its evidentiary position that temporary energy customers should continue to be required to make some contribution to fixed costs. Amoco disagreed with IPCAA that there should be any contribution to fixed costs. Amoco submitted that the evidence of TransAlta is that the proposed contribution to fixed costs is to cover the costs of generation and transmission paid by the distribution Decision U99035 Page 104 10 August 1999


company, not just for distribution costs. Finally, Amoco noted that it takes service at the transmission level and distribution costs are not relevant to its situation. IPCAA

IPCAA noted that TransAlta could no longer interrupt on the basis of energy shortage, only on the basis of distribution system problems, and suggested that the term temporary energy be replaced with the term “DISCO Opportunity Service” (DOS). For customers taking service from the transmission system the TA GOS charge should apply but there should be no further DISCO charge. With respect to qualification for opportunity service IPCAA submitted that the TA should be responsible for making a qualification decision regarding availability of transmission service. IPCAA also maintained that a problem has arisen with “load retention” situations vis B vis Rate 720. IPCAA stated that temporary service has become more expensive than firm service and attributed this to the market power of too few generators and the lack of a functioning demand side market. It recommended that due to the distortions in the generation supply market, temporary energy customers who wish to convert to a firm price rate should be allowed to do so. With respect to the actual proposed charge for temporary service IPCAA noted that the proposed rate schedule for Rate 6600 only states that TransAlta may negotiate an individual rate with a customer applying for service. IPCAA submitted that a reasonable measure of the cost of distribution service is the difference between Rates 6300 (distribution service) and 6400 (transmission service). This ranges from 0.394/kWh for the peak period to zero for the off-peak period. IPCAA recommended the charge be no higher than 0.154/kWh. IPCAA stated that while it is amenable to allowing TransAlta to negotiate a different rate, the maximum allowable charge should be the 0.154/kWh should negotiations not succeed with individual customers. Position of TransAlta

TransAlta disputed Amoco’s assertion that export customers will be treated better than intra Alberta customers in the TransAlta Provost arrangement, stating that there is no evidence on record in either this proceeding or the Provost proceeding to support Amoco’s position. TransAlta maintained that the sole beneficiaries of any contribution to fixed costs by export customers will be the firm customers who will see their rates reduced. In conclusion TransAlta submitted that, in the period leading up to full customer choice, TransAlta should be allowed to retain the flexibility inherent in the temporary energy rate. In this manner contributions to fixed costs can be continued for the benefit of firm customers who are responsible for the costs of existing infrastructure. Board Findings

The Board believes that, since firm customers pay for the fixed costs of infrastructure through their rates, it would be unfair to deprive firm customers of the opportunity to recover some rent for the infrastructure they have effectively paid for. The Board considers that in this period leading to full market choice, the fairest means to accomplish this is to allow TransAlta to negotiate an individual rate with a customer, as is proposed in the rate schedule.



The Board notes that the TA’s GOS rate includes a Transfer Charge30 which is based on a 50/50 sharing between the TA and the DISCO of margin the DISCO negotiates with the end-use customer, but cannot be less than $0.0030/kWh. The Board therefore considers that the DISCO is negotiating on behalf of the TA and Alberta customers to maximize the contribution towards the fixed costs of both the distribution system and transmission system. Therefore, the Board does not accept Amoco’s or IPCAA’s submissions regarding transmission served customers. The Board also does not believe that there is sufficient evidence to support Amoco’s assertion that export customers, as in the TransAlta Provost arrangement, will make no contribution to fixed costs and will therefore be potentially better off than Alberta customers. The application in question pertained to a facilities matter and the subsequent decision did not set a tariff. The Board also notes the recommendation of IPCAA, made in argument, that temporary energy customers should be allowed to convert to a firm price rate if they wished. TransAlta did not comment on this proposal. As a general principle the Board does not believe that existing customers should be subject to conditions more stringent than new customers coming on to the system. The Board therefore considers that temporary energy customers seeking to switch to a firm rate should be allowed to do so, subject to any notice requirement in a particular customer’s contract. In respect to the conditions of service under this rate, the Board also agrees with certain of the points raised by IPCAA. The availability of generation services is determined by the market and the availability of transmission opportunity service should be determined by the TA. Therefore, the Board directs TransAlta to consider only distribution related constraints when its customers otherwise qualify for temporary energy. Further, the Board directs TransAlta to only curtail energy purchases for distribution system security reasons or, at the TA’s request, for transmission system reasons. In Section 3(a), the Board directed TransAlta to separate its Delivery Charge into TA Billings and DISCO Services components for all rates. The Board also directs TransAlta to amend its temporary energy rate schedule to allow a customer to negotiate a temporary rate which flows through the actual pool price if the customer prefers that to negotiating a fixed rate. As the total charges payable by temporary energy customers are negotiated, the Board considers that it would be inappropriate to change the overall rate level payable under this price schedule by including the H credit in the Energy Supply charges. (12) Real Time Pricing C Rate 6700

At present all energy obtained through legislative hedges is sold to TransAlta’s customers through embedded rates. Energy purchased on the spot market is currently resold at the Power Pool of Alberta’s hourly price under TransAlta’s temporary energy, Real Time Pricing, and Real Time Pricing Transition Alternative rate schedules.


30 Decision U97065, p.629


TransAlta plans to continue reselling spot purchases under these rates but has proposed to conduct an auction for customers who wish to purchase energy on TransAlta’s market based Real Time Pricing Rate 6700. The rate is proposed to be available until 31 December 2000. The auction process is proposed to include the following conditions:

• customers must have interval recording metering, • customers can bid up to a maximum of their total load, • Real Time Pricing Rate 6700 has a minimum one year term, and • customers can make positive, negative or zero bids.

There will be a reserve bid equal to the cost of obtaining a hedge. If the auction process does not produce sufficient bids to cover energy purchases in excess of the legislative hedges, TransAlta proposed to obtain a hedge for that excess energy. TransAlta claimed that customers on embedded rates will be neutral or better off as to whether TransAlta manages the excess energy through the auction offering or through hedged purchases. Position of the Intervenors

IPCAA

IPCAA stated that it understood Rate 6700 to be a mechanism by which TransAlta will hedge purchases made for its customers, and whereby TransAlta will auction off to customers the right to take power at the hourly pool price. IPCAA expected that with pool prices well above the hedged cost of energy it is unlikely that any customers would choose to pay for this “right” and noted that TransAlta is willing to accept positive, negative or zero bids. IPCAA claimed that TransAlta has essentially proposed to purchase additional hedges from its customers and sees nothing wrong with that as long as TransAlta does not expect other customers to pay the cost of such hedges. It recommended that TransAlta be allowed to purchase hedges from customers as long as the costs of the hedges are not imposed on TransAlta’s other customers. Position of TransAlta

TransAlta stated that it proposed the rate and associated auction to provide customers with the opportunity to accept the Power Pool hourly price. TransAlta submitted that the customer who is successful in the auction would be subject only to the hourly pool price for the Generation Service Charge and would be free to enter into any arrangement desired with marketers or new suppliers of generation. Board Findings

The Board notes there was very little comment upon this proposed rate and that no one opposed it. The Board also considers that the concept of affording customers the opportunity to choose the pool price is consistent with the movement to an open market. The rate as proposed by TransAlta is therefore approved. Decision U99035 Page 107 10 August 1999


(13) Direct Access Tariffs C Rate 6800

Section 31.4 (1) of the EU Act requires TransAlta to prepare a DAT. A DAT is a rate option to be provided to large energy users that would allow customers to have direct access to the pool price and, if they so desire, to settle with the power pool for their energy purchases. Section 31.6 of the EU Act and sections 4, 5(2), and 6 of Alberta Regulation (AR) 168/98 of the EU Act, the Distribution Regulation, set out the requirements in designing a DAT. Section 4(1) of AR 168/98 states:

4(1) Instead of setting out a charge for the rate referred to in section 31.6(1)(c) of the Act, the direct access tariff required under section 31.4(1) of the Act must set out a charge that represents a fair and reasonable allocation to direct access customers of the costs of operating the electric distribution system.

Section 4 of the Distribution Regulation requires that the DAT have a fair and reasonable charge for reservation payments and a fair and reasonable credit for entitlements. The Distribution Regulation also requires that the DAT be designed to encourage customers to respond to the pool price. A further requirement is that customers be allowed to elect to pay one of two charges for the purchase of energy where each charge is based on the prevailing pool price. One election is to pay a variable charge equal to the actual hourly pool price (actual pool price DAT). The other election is to pay a fixed charge based on the forecast average pool price in the TOU period the energy is used (TOU DAT). The Distribution Regulation31 requires that a DAT customer give six months notice of the effective date of the change if it elects to be billed pursuant to another tariff offered by the distributor. TransAlta responded to the requirements of section 31.4(1) of the EU Act by proposing Rate 6800. Rate 6800 is available to customers with an interval recording meter and is available until 31 December 2000. The rate has three options depending on the level of a customer’s normal billing capacity: Rates 6820, 6830, and 6840. TransAlta would allow customers who so desired to settle directly with the power pool for the energy they purchase. Customers who choose DAT must remain on the DAT for a minimum of 12 months or as set out in the DAT regulations, to ensure that DAT customers do not switch rates to take advantage of seasonal price fluctuations to the detriment of all other customers. The delivery service charges for the three rates are the delivery service charges for Rates 6200, 6300, and 6400 respectively. The DAT includes the delivery service charge plus a generation service charge that has three components: an energy charge equal to the Power Pool of Alberta Hourly Price, an energy charge equal to the reservation payment, and an energy credit equal to the UOV credit. The reservation payment is proposed to be based on a forecast of one-twelfth of


31 EU Act Sec 31.6 (8)(9)(10)


the annual reservation payment divided by the energy purchased by the distribution function through legislated hedges for each month. The UOV credit will be based on the actual total UOV credit received by the distribution function divided by the energy purchased through legislated hedges each month. On behalf of IPCAA, the Drazen Consulting Group Inc. (DCGI) proposed a different version of the DAT (the IPCAA DAT). The rate structure for the IPCAA DAT assumes that all rates will be unbundled into generation, transmission and distribution components. The IPCAA DAT has the following properties:

• energy usage will be charged at actual hourly Pool Prices; • the UOV is determined by formula; and • the volume of UOV and reservation payment are fixed by contract for the period

through the year 2000.

The IPCAA DAT was designed so that the contract obligation amount and the contract UOV entitlement volume are independent of actual usage so that customers are provided the proper incentive to sign up for the DAT and respond to hourly Pool Price signals. This is intended to mirror the design of the DISCO’s hedges. On behalf of IPPSA/SPPA, Mr. Knecht proposed another version of the DAT whereby the SC/RV charge would be fixed and based on a demand rather than on an energy charge consistent with the EEMA regime. The Board issued Decision U99015 dated 8 February 1999 implementing TransAlta’s proposed DAT as a Temporary Direct Access Tariff (TDAT) pending a final decision on the Application. The Board considered that implementation of some form of DAT might reduce the potential supply shortage on the Alberta system by providing a mechanism that would allow customers to reduce or curtail load in response to pool price Position of the Intervenors

IPCAA

IPCAA noted its desire that a properly designed and functional DAT be implemented as soon as possible. IPCAA submitted that the DAT proposed by TransAlta-DISCO is fundamentally flawed and IPCAA does not expect that customers will make use of it. In response to TransAlta, IPCAA stated that TransAlta’s proposed DAT does not meet the provisions of subsection 4(4) of the Distribution Regulation as a rate that will not be used cannot encourage customers to be price responsive. Alternatively, the IPCAA DAT would be well utilized because it would provide customers the certainty they require to be able to make the long-term decisions to be responsive to Pool Price. IPCAA noted that the current environment is characterized by high and extremely volatile Pool Prices and also by customer concerns about the potential abuse of market power.



IPCAA stated that the key difference between the DAT proposed by TransAlta and the IPCAA DAT is that, under the IPCAA DAT, customers will receive a share of the UOV based on their average usage during a month. IPCAA stressed the importance of protecting the customer from forecast risk. Also, the DAT should provide an incentive for the customer to respond to variations in the Pool Price. IPCAA stated that, under the TransAlta proposal where a DAT customer would receive a share of the UOV based on actual usage, if a customer reduces usage at times of high pool price, the amount of UOV refund is reduced thereby diminishing the customer’s incentive to reduce usage. IPCAA stated that the DAT, as proposed by TransAlta, lacks the required certainty to be used as a hedge by customers. IPCAA further noted that its members are the most likely customers of the DAT and emphasized that they believe that the DAT proposed by TransAlta will not work. IPCAA submitted that it is important to carefully consider what the customers have to say about what rates they will or will not use. IPCAA submitted that customers are saying that they will not use the TransAlta DAT and that they would use a rate like the IPCAA DAT. IPCAA therefore proposed that TransAlta be directed to design a DAT in accordance with the IPCAA DAT. In response to TransAlta’s criticism that the IPCAA DAT is too complicated to implement, IPCAA stated that it would be problematic to implement only if TransAlta makes it so. IPCAA submitted that, with a modicum of good faith and cooperation on the part of TransAlta, there was every reason to believe that a workable DAT could be implemented in relatively short order. IPCAA clarified its proposal that a customer’s UOV entitlement shares should be set by using a combination of actual customer usage and class load patterns. Only if a standard load shape does not work, would it be necessary to negotiate with customers on their forecast load shape. In response to the FIRM Customers suggestion that temporary customers (Rate 720) are not eligible for the DAT, IPCAA submitted that, pursuant to the legislation, there should not be any such restrictions on eligibility for the DAT. IPCAA stated that, since the definition of a Direct Access Customer is provided in section 1(1)(b.3) of the Act, the Board cannot approve any restriction of direct access customers. IPCAA submitted that Rate 720 customers are eligible to receive service under a DAT as they fall within the definition provided. With respect to the eligibility of Option 12 and 21 customers, IPCAA stated its confidence that if a court were ever asked to decide the question, it would conclude that the provisions of the EU Act that stipulate eligibility for a DAT override any aspect of TransAlta’s rate schedules, terms and conditions or contracts with which they are inconsistent. However, IPCAA conceded that loads that are currently served under Options 12 or 21 would not be eligible for DAT service as long as the relevant contracts remain in force. IPCAA submitted that any load served under an Option 12 or Option 21 contract that is terminated, whether by agreement of the parties or at the direction of the Board, should be immediately eligible for the DAT. IPCAA clarified that it did not oppose interim approval of the TransAlta DAT. However IPCAA was concerned that an interim approval could foreclose the implementation of a workable alternative. IPCAA stated its reservations about the feasibility of directing TransAlta to work Decision U99035 Page 110 10 August 1999


with IPCAA in designing a DAT. IPCAA recommended that the Board reject TransAlta’s proposed Rate 6800 and direct TransAlta to replace it with a DAT consistent with the IPCAA DAT. IPCAA suggested that, since TransAlta has the required customer information, it should be possible for TransAlta to complete the process in a relatively short time and therefore a specific deadline should be established for TransAlta to complete the new rate design. IPCAA recommended an implementation date not later than 1 February 1999. TransCanada

TransCanada noted that consideration should be given to AR 168/98 s.4 and 5(2) in determining whether to approve a proposed DAT. TransCanada submitted that a DAT should be approved only if it encouraged customers to alter their consumption of electric energy as the pool price changes. TransCanada also submitted that it is important to consider whether a “successful” DAT is an important part of the restructuring process and which of the various proposed forms of the DAT will be the most appropriate mechanism to achieve the legislated purposes. TransCanada suggested that an inappropriate rate design for the DAT could result in delays or failure in implementing a competitive marketplace. TransCanada noted section 5(2) of AR 168/98 that states that a DAT must be designed so as to encourage customers to alter their consumption of electric energy as the pool prices changes. TransCanada suggested that TransAlta appeared to be indifferent on the importance of the DAT creating a long-term price signal. TransCanada submitted that if TransAlta’s perspective were accepted, little would change in Alberta. TransCanada also noted that a customer must take its entire load under DAT if it wants to use the rate. TransCanada submitted that, while TransAlta apparently sees the DAT primarily as a mechanism for customers to respond to Pool Price by adjusting their load, the DAT proposals by Mr. Drazen and Mr. Knecht are more comprehensive as they include the short and long-term effects of the DAT and better encourage customers to alter their consumption of electric energy as the pool price changes. Therefore, TransCanada recommended that the DAT described by IPCAA and Mr. Knecht better achieved what TransCanada considered should be the broad purposes of the DAT. TransCanada submitted that the following features are required to achieve a successful DAT:

• Develop price-responsive load, • Provide mechanisms so customers can fully hedge their pool price risks, • Set the contract obligation amount and contract UOV on a forecast basis independent of

actual usage, • Provide the means by which customers can participate in the competitive energy market, • Pass through the hedge value to the customer, • Contribute to reducing market power problems by reducing the ability of GENCOs to

increase the average Pool Price, • Have a common structure design for DAT and the associated regular tariff, • Help to avoid unnecessary costs related to supply/demand not being in equilibrium

including reducing the risk of brownouts,



• Incorporate pool price flow through signals, and • Provide customers with the full benefit of curtailing or reducing load in response to high

pool prices. TransCanada noted that section 31.6(3)(b) of the EU Act requires that a forecast of pool prices be provided in the DAT. TransCanada stated that TransAlta did not supply its forecast until it filed its 1999/2000 Phase I filing. TransCanada stated its concern that TransAlta did not rely on the forecast of hourly pool price and provided the pool price to intervenors late in the process despite the requirements of section 21.6(3)(b) of the EU Act. TransCanada submitted that TransAlta has information on UOV credits and Reservation Payments but has failed to provide sufficient information upon which customers could determine what the DAT might cost a customer in 1999 and whether a customer may wish to choose the DAT. Since TransAlta was seeking interim approval of the DAT on 5 November 1998, this concern had immediate consequence. TransCanada submitted that TransAlta has introduced volume-related price uncertainty to potential DAT customers in its rate design. TransCanada supported the IPCAA and IPPSA forecast methodology for determining UOV entitlements and reservation payments rather than using actuals. TransCanada submitted that considerable weight should be given to relying on forecasts for this purpose as it is the method supported by customers who are interested in DAT and who are likely to make decisions on when to alter consumption of electric energy as pool price changes. TransCanada proposed that, should TransAlta’s proposed DAT be accepted, that TransAlta be required to expeditiously develop a DAT rate calculator that can be used by customers potentially interested in the DAT to estimate what their charges could be. This rate calculator should include TransAlta’s 1999/2000-pool price forecast, a proper allocation of the UOV credits and the reservation payment attributable to each rate class. The rate calculator should be designed so pool price forecasts, other than TransAlta’s, and adjustments to the reservation payment can easily be inserted into the calculator. Normal inputs for customer demand and energy should be included. TransCanada also proposed that TransAlta’s DAT be modified to include the upgrade proposed by Mr. Knecht to adopt the 1999 forecast for reservation payments and UOV credits as the basis for those components of the Rate 6800 generation charge. Also, a second option should be provided that will allow a customer to choose the DAT approach recommended by IPCAA. TransCanada noted that, for a customer to make use of the DAT, it must take its entire load requirement under the DAT. In other words, a customer is not allowed to take only a portion of its load under DAT although this is not stated on the tariff sheet. TransCanada noted that other utilities, including APL, allow rates to be stacked. Also, TransAlta has historically offered stacked rate arrangements such as taking service under both Rate 720 and Rate 790.



TransCanada submitted that customers should be allowed to stack the DAT with other hedged rates, as it would encourage customers to move towards the DAT. TransCanada also recommended that the DAT should be modified to allow for sales of hedges back to TransAlta, to other DISCOs, or to third parties. TransCanada submitted that, by including a hedge in the DAT but not allowing a customer to resell the hedge, customers have less of an inducement to use the DAT. TransCanada submitted that the opportunity that a hedge allocated to a customer could be sold to another party would further increase interest in the DAT and encourage a competitive market. TransCanada questioned TransAlta’s submission that its proposed DAT will work for those customers who offset their reduced consumption in high priced periods with increased consumption in low priced periods. TransCanada questioned what portion of DAT customers have the ability to respond by shifting load as opposed to customers that are able to curtail load in high price hours. TransCanada also noted that TransAlta’s main concern appeared to be with their administrative burden rather than with encouraging the development of price responsive load through a DAT that is acceptable to its customers. FIRM Customers

The FIRM Customers noted that there are four main areas to consider in examining the merits of the different DAT proposals. They are (1) the appropriate design of the DAT; (2) eligibility for the DAT; (3) the feasibility of combining firm rates with DAT for part of a customers’ load (rate stacking); and (4) the marketing or trading of entitlements under the DAT. The FIRM Customers stated that the essential difference between TransAlta’s proposed DAT and the IPCAA DAT is that the IPCAA DAT presets entitlements to UOV by a specific DAT customer on an hourly basis whereas TransAlta passes through UOV credits on an actual basis calculated as an average over a specified period. With respect to reservation payments, the Drazen proposal presets the reservation payments based on customer contract energy whereas TransAlta passes the reservation payments through on the basis of actual usage. The FIRM Customers noted that, while they do not disagree that a forecast basis for passing UOV to DAT customers might provide added incentive for loads to be price responsive, there are a number of concerns respecting the practical application of the principle. The FIRM Customers stated it would be difficult to establish a baseline for each customer, as there would be difficulties with data availability and confidentiality. The FIRM Customers noted TransAlta’s statement that previous attempts at establishing baselines for customers lead to customer disputes. Another concern is how the strike price will be adjusted each hour to reflect the DISCO’s net cost of purchases. The FIRM Customers noted that if the strike price adjustment is



not carried out accurately every hour, non-DAT customers could lose their hedges relative to other hedged customers due to growth. The FIRM Customers suggested that the IPCAA DAT implicitly assumed that entitlements freed up by a DAT customer when it curtails load in a certain hour would be of value to the TransAlta DISCO in the same hour. The FIRM Customers stated that paying UOV credits to a DAT customer in an hour when the TransAlta DISCO does not have the requirement to call any entitlements for other non-DAT loads would result in additional costs and risks to TransAlta DISCO. This could in turn result in adverse impacts for non-DAT customers. The FIRM Customers also suggested that the IPCAA DAT provides a disproportionate incentive to contract for new load to lock-up incentives. This also could be to the detriment of non-DAT customers. For these reasons, the FIRM Customers recommended that the TransAlta DAT be approved on an interim basis. The FIRM Customers also proposed that parties should continue negotiating practical alternatives so that pool price responsiveness is enhanced. If a DAT is approved that is similar to the IPCAA DAT, the FIRM Customers recommended that the following be considered. Firstly, baselines should incorporate appropriate load profiling techniques and testing to ensure there is no undue shift in risk from DAT to non-DAT customers or the DISCO. The baseline should not include any temporary energy under Rate 720 or loads under interruptible contracts. It is necessary to develop a practical method for calculating and adjusting strike prices. Also, any UOV credit passed by TransAlta DISCO to a DAT customer in an hour when the customer curtails load should reflect the value received by TransAlta DISCO in that hour. Lastly, a mechanism should be put in place to monitor new loads to prevent any attempt to lock-up entitlements that are not consistent with the customers load profile. The FIRM Customers supported TransAlta’s position with respect to the eligibility for DAT, namely that existing temporary energy customers are not eligible for DAT and customers currently under interruptible or price responsive contracts must continue to honour their contracts. The FIRM Customers stated that customers taking service under temporary energy (Rate 720) are served under an unhedged rate and that these customers should not qualify for firm service or DAT, as they are, by definition, temporary loads. With respect to price responsive loads such as Option 21, the FIRM Customers submitted that conversion to DAT would dampen the price sensitivity of these customers and therefore defeat the purpose of the DAT rate. With respect to Option 12 customers, the FIRM Customers submitted that parties should not be relieved of their obligations under a contract because circumstances have changed which would allow a perceived better deal. The FIRM Customers noted TransAlta’s position on the need for simplifying assumptions to determine what portion of load is taken on what rate if rates are allowed to be stacked. The FIRM Customers recognized TransAlta’s concern over simplifying assumptions, however the FIRM Customers considered that stacking of rates would provide customers the ability to try out DAT without exposing all of their load to pool price risk management. The FIRM Customers Decision U99035 Page 114 10 August 1999


considered that this could be useful to mid-size commercial and institutional customers contemplating direct access. The FIRM Customers recommended that TransAlta implement screening procedures to enable customers to stack rates and therefore to encourage customers to make use of price responsive rates. The FIRM Customers noted TransCanada’s recommendation that the DAT be modified to allow for the sale of hedges back to TransAlta, to other DISCOs, or to third parties. The FIRM Customers submitted that, if customers wish to trade their entitlements through bilateral contracts with other customers or DISCOs, it should be left to the contracting parties. The FIRM Customers suggested that the Board did not need to become involved in the marketing of entitlements at this time. The FIRM Customers submitted that the manner in which IPCAA and IPPSA/SPPA proposed to pass through the obligation value credits from legislated hedges to DAT customers ignored the fundamental structure of the hedges. The FIRM Customers noted that hedges are fixed at the DISCO level. Each DISCO is allowed a fixed percentage of regulated generation on an hourly basis that must then be spread over a varying and increasing the Alberta Interconnected System (AIS) load. The FIRM Customers submitted that, unless a mechanism is in place to ensure direct access and non-direct access customers become unhedged at the same rate as growth occurs the proposals that lock in the hedge will result in discrimination favouring direct access customers. The FIRM Customers noted TransCanada’s suggestion that a forecast of 1999 reservation payments and UOV credits should be the basis for Rate 6800 generation charges. The FIRM Customers recommended that this should apply to all tariffs and should be adjusted each year by functional component to reflect a given year’s costs and credits. IPPSA/SPPA

IPPSA/SPPA had the following questions regarding TransAlta’s proposed DAT. (1) What level of unbundling of the DAT is appropriate? (2) What is the appropriate magnitude of the reservation payment and UOV credit for each rate class? (3) Should the reservation payment/UOV credit be recovered on a fixed or variable basis? IPPSA/SPPA submitted that TransAlta’s proposal to bundle transmission and distribution costs in its DAT represents bad rate design and regression from progress made to an unbundled tariff. IPPSA/SPPA stated that, by combining the pool price, reservation payment and UOV cost/credit items into a single charge, the market price signals are masked. IPPSA/SPPA also noted that, since the UOV credit tends to offset cycles in pool prices, the market price signal is further obscured. IPPSA/SPPA submitted that it is useful for customers to begin to see a reasonable approximation of actual market price signals on their bills. IPPSA/SPPA stated that TransAlta has Rate 780, which is a direct access tariff that has more unbundling than the proposed Rate 6800. IPPSA/SPPA submitted that the unbundling of tariff



charges that currently exists in Rate 780 should be maintained. IPPSA/SPPA also noted that APL proposes to unbundle its delivery charges for its DAT into transmission and distribution. IPPSA/SPPA noted that TransAlta has proposed a per-kWh reservation payment charge and a per-kWh UOV credit, based on an actual UOV for the DISCO. IPPSA/SPPA stated that, in effect, this sets the stranded cost/residual value (SC/RV) component of costs at the average for all rate classes eligible for the DAT of the DISCO. IPPSA/SPPA stated that by providing a company-average reservation payment and UOV credit, TransAlta’s proposal provides the same per-kWh SC/RV charge/credit to industrial DAT customers as to residential and small commercial customers. IPPSA/SPPA submitted that a specific DAT could not be developed without addressing the issue of allocating SC/RV costs. Also, by providing a lower SC/RV credit to industrial customers than that which is embedded in existing rates, IPPSA/SPPA stated its concern that that TransAlta’s proposed DAT will not attract industrial customers before TransAlta’s proposed allocation of SC/RV in embedded cost rates takes effect. Therefore, IPPCA/SPPA proposed that, to the extent that a DAT is needed immediately, any customer who takes service under the temporary DAT should be allowed to switch to a revised version at no cost and with no penalties. IPPSA/SPPA noted that TransAlta’s proposal makes the reservation payment/UOV credit variable with energy consumption. IPPSA/SPPA noted that, if a customer reduces energy consumption in response to high pool prices, some of the customer’s entitlement to residual value is lost. TransAlta does not lose that entitlement since a DISCO’s entitlement is not based on actual usage but on a pre-set amount. Therefore, an increase in load does not provide any additional legislated hedges. However, IPPSA/SPPA stated that under TransAlta’s proposal, if a DAT customer increases load, its entitlement increases. Additionally, IPPSA/SPPA stated that the variable nature of the reservation payment and UOV charges distorts the price signals in the pool price flow through. IPPSA/SPPA proposed that the SC/RV charge should be a demand rather than an energy charge as this would reduce the economic distortion associated with a non-market price signal and make the treatment of these costs more consistent with the old regime. IPPSA/SPPA noted that TransAlta proposed to base the UOV credit on the actual credit received by the TransAlta DISCO per kWh of load covered by legislated hedges. IPPSA/SPPA proposed that the SC/RV charge/credit should be fixed on some measure of contract demand or contract energy. Therefore, any reductions in hourly energy consumption would not reduce entitlement to residual value, nor would the hourly energy prices be distorted. IPPSA/SPPA recommended that the regular rate SC/RV charge for each rate class should be the total allocated generation costs under the fixed-variable method less total allocated 1998 pool price costs divided by the billing demand determinant for that class. Therefore, for each of the Rate 6800 subclasses, the tariff will contain a base SC/RV charge, equal to the matching class’ SC/RV charge, multiplied by an adjustment factor. The adjustment factor would consist of the actual monthly total TransAlta SC/RV value divided by the 1998 monthly SC/RV value. IPPSA/SPPA also proposed that new, unhedged loads should not be entitled to SC/RV and will therefore not be uneconomically Decision U99035 Page 116 10 August 1999


encouraged. IPPSA/SPPA stated that it is anxious that a useable DAT be implemented as quickly as possible. However, IPPSA/SPPA does not believe that a useable DAT can be implemented without resolving the issue of allocating SC/RV and structuring the “regular rates.” Position of TransAlta

TransAlta noted that Section 4(2)(b) of the Distribution Regulation provides that the Board shall examine the reservation charge and the entitlement credit for the DAT based on forecast consumption. However, Section 4(3) allows for a method that uses actual consumption, rather than forecast, if that method better achieves the principle stated in Section 4(4) that a DAT must be designed so as to encourage direct access customers to alter their consumption of electric energy as pool price changes. TransAlta stated that its proposed DAT uses actual rather than forecast consumption so as to encourage direct access customers to alter their consumption in response to pool price changes. TransAlta therefore submitted that its proposed DAT satisfies the legislative requirements. TransAlta submitted that there is an inherent conflict between the requirement to pass on legislated hedges and the principle that the DAT is designed to encourage customers to alter consumption of electric energy as the pool price changes, given that the purpose of a hedge is to mitigate the impact of increasing prices. TransAlta stated that it proposed to pass on the reservation charges and obligation value credits based on the actual average monthly values and the actual energy distributed by the distribution function in order to mitigate the conflict. TransAlta considered that the legislative principle was therefore achieved as its approach provides a hedge against average monthly pool price levels and flows the hourly pool price to customers. Customers will receive the value of the hedge and have an incentive to alter their consumption of electric energy. TransAlta also submitted that, by basing its DAT on actual energy consumption on a customer-by customer basis rather than on a forecast basis, its proposed DAT will avoid the problems that arise when forecasts do not materialize. TransAlta stated that a customer who elects to put load on the DAT would face the hourly pool price. The customer can achieve cost savings by responding appropriately in low and high priced hours. The customer is also protected from the average level of pool price in the month because of the obligation value credit in the month. TransAlta submitted that under its proposed DAT, if pool prices are high throughout a month, the DISCO obligation value amount will also be high and will be passed to the customer through the Obligation Value Credit portion of the DAT. TransAlta also noted that, to the extent that a customer reduces load in the highest price hours, the pressure on the system will be relieved to the benefit of all customers. TransAlta stated that the IPCAA DAT assumed that the DAT Contract Amount could be set at a level that will remain appropriate for the duration of the rate through to the end of 2000. TransAlta submitted that setting the DAT Contract Amount is critical in determining the total bill for the customer. TransAlta contended that it is impossible to fix the DAT Contract Amount to the load that would have materialized had the customer stayed on embedded rates because,



once the customer changes its consumption pattern to respond to price signals, the benchmark is lost. Additionally, even if the DAT Contract Amount can be successfully negotiated, there may be a need to renegotiate the Contract Amount at a later date. IPCAA also proposed that the DAT Contract Amount could be based on forecast usage while acknowledging that the forecast is made with the intent of making it wrong. TransAlta submitted that, to the extent a customer responds to pool price, the forecast DAT Contract Amount would be wrong. TransAlta stated that the primary weakness with the IPCAA DAT is that it requires the construction of a DAT Contract Amount for each customer who may be able to offer price responsive load so that an entitlement amount can be calculated for each customer. IPCAA proposed that the amount be set ahead of time and held constant, despite any increases or decreases in the customers’ actual level of usage for a period of two years. TransAlta further noted that, under the DAT Contract Amount concept, there is the need to set a demand for each customer, to establish load factors for each customer, to establish an hourly load pattern, and it may be necessary to customize the load pattern for various customer groups. For some customers it may be necessary to adjust the load profile to reflect ambient temperature and seasonality. TransAlta suggested that any customer whose load factor is greater than the average for the class, will want a DAT Contract Amount based on its individual load factor and load shape as it will enhance its Unit Obligation Credit. Since each DAT customer will have a significant portion of its monthly bill dependent on the outcome of the negotiations on the DAT Contract Amount, it is expected that the negotiations will be difficult and protracted. Also there is the potential for inappropriate entitlements for customers whose load changes over time in a manner not foreseen when the Contract Amounts are initially set. TransAlta submitted that the IPCAA DAT does not ensure that a customer will be protected from paying more than it would have had it remained on Rate 790 since the DAT contract amount will never exactly match the customer’s actual consumption. If a customer consumes more energy than the DAT contract amount and the pool price is higher than embedded rates, the customer will pay more than it would have on Rate 790. TransAlta submitted that, under its proposal, the entitlement to a DAT customer is passed through in the same way as it is passed through to customers on embedded rates. A customer on embedded rates receives this entitlement through the rate applied to its actual load, and the same method would apply to the DAT customer. TransAlta also submitted that this method will ensure that the total entitlement received by the DISCO would be passed through to each customer on an equivalent basis, and if all customers were to take a DAT rate, the total DISCO entitlement would properly flow through to each and every customer. TransAlta noted that IPCAA recommended that the TransAlta DAT should not be approved because customers would not use the rate. TransAlta submitted that, before it is decided whether or not customers will use the proposed DAT, the rate must be proven to be workable. Decision U99035 Page 118 10 August 1999


With respect to the DAT proposed by IPPSA/SPPA, TransAlta submitted that resolution of the SC/RV issue prior to implementation of the rate would significantly delay the implementation of a workable DAT. Additionally, TransAlta objected to the IPPSA/SPPA proposal, that new unhedged load should not be entitled to SC/RV, as it discriminates against new load in relation to existing load. TransAlta disagreed with TransCanada’s proposal to implement two separate DATs. TransAlta stated that the implementation of two rates designed to achieve the same purpose is without precedence and may cause confusion among customers and would unnecessarily increase administrative costs. With respect to TransCanada’s proposal that the sales of hedges back to DISCOs or third parties be allowed, TransAlta submitted that the request ignored Section 37 of the EU Act. This section provides that an entitled electric distribution system has an obligation to pay reservation payments and lacks any provision by which the entitled electric distribution system can alleviate itself of this liability. Therefore, if a third party assumes the payment of reservation payments and then defaults, the distribution function is still required to make such reservation payments. TransAlta therefore recommended that this proposal be denied. Board Findings

Although a new DAT will not be available until after the Board’s review of TransAlta’s refiling, the Board considers it inappropriate for the Temporary DAT approved in Decision U99015 to continue to be available to new customers under terms that differ from the new DAT. Therefore, the Board directs that TransAlta close the Temporary DAT to new customers as of the date of this Decision. To the extent that DAT customers reduce load in the highest price hours, the pressure on the interconnected system will be relieved to the benefit of all customers and the DISCOs which supply them. There will be a downward pressure on the cost of energy, particularly at very high pool price times. The demand response of customers will thus enhance the efficiency of the market. Therefore, the Board considers that a properly designed DAT is important to the interconnected system. The Board does not consider that the DAT should be applicable to customers served by isolated generation since the costs incurred by the DISCO to serve them may be significantly different from the Energy Supply costs on the AIS. To improve the efficiency of the demand side of the market, the Board would prefer that all large customers move to the actual pool price DAT and see the actual hourly variation in pool price. The advantage to the actual pool price DAT is that customers would see and might respond to actual short term spikes in the pool price. However, the Board recognizes that some customers may not be prepared to move away from fixed rates at this time.



The Board considers that there is a clear differentiation in average pool prices between the TOU periods and also notes the differentiation in TA rates (TA Rate GSS) between on-peak and off-peak periods. Therefore, TOU rates embody a price signal to customers by reflecting the typically higher costs during peak hours and lower costs in off-peak hours and seasons. The Board considers that a properly designed TOU DAT will provide superior price signals as compared to a single fixed rate. A single fixed rate can only reflect the forecast average cost of energy throughout all of the year for the entire class based on forecast average class consumption patterns. The TOU rate can reflect the average expected variation in pool price with the season, day of the week and time of the day and allows customers the opportunity to vary their actual consumption to take advantage of lower energy cost periods. The Board considers market efficiency will be enhanced if customers who would have been on a non-TOU fixed rate subscribe to TOU DAT rates. In determining an appropriate design for the DAT, the Board must look at the appropriate charges for Energy Supply, TA Billings and DISCO Services. The Board considers that the DAT should be designed so that DAT customers make a decision on when they will take energy based on the prevailing pool price. The DAT should not include a discount or incentive payment relative to fixed price rates. The Board agrees with parties that the Power Pool of Alberta hourly price is the appropriate Energy Supply price signal that should be seen by DAT customers. To eliminate any incentive or disincentive which is not related to pool price, the Board considers that the TA Billings, DISCO Services and any other ancillary charges should be the same for DAT as for firm fixed price rates. The Board notes that TransAlta’s proposed DAT was designed so that its non-generation charges for proposed Rates 6200, 6300 and 6400 also apply to the DAT. Section 4 of the Distribution Regulation requires that the DAT have a fair and reasonable charge for reservation payments and a fair and reasonable credit for entitlements. The Board finds that a fair and reasonable charge and credit is reflected in the “H” amount which is derived as described in Section 3(b). Using the same per kWh fixed amount “H” for DAT and fixed rate customers should, on a forecast basis, leave TOU DAT customers with typical usage characteristics no worse off than if they had chosen fixed price rates. The TOU DAT will provide a benefit on a forecast basis for customers who plan to respond appropriately to the TOU energy price differentials. As a result of the energy-based allocation of RP even customers with low load factors who are able to shift load in response to pool price will benefit from the DAT. The Board notes that Rate 6200, 6300 and 6400 propose energy charges based on the forecast average pool price in the TOU period. The Board finds that these rates meet the requirement in the EU Act that a fixed charge TOU DAT rate option be provided. However, the EU Act 31.6(2)(b) specifies that the charges to apply for certain hours reflect an expected average cost calculated using a forecast of pool prices for those hours. In Section 2(a)(1) the Board determined that the TOU energy charges should reflect only the forecast pool price, without any premium, during the period the rate is in effect. In Section 2(a)(1), the Board concludes that the Decision U99035 Page 120 10 August 1999


forecast for rates arising out of this proceeding should be based on the actual 1998 pool price record. The Board also considers that the TOU option should pass through to customers the variation with time of use in the TA’s charges to TransAlta. TransAlta’s rates have separate off-peak and on-peak energy transfer charges as does the TA. However, the Board directs TransAlta to design its TOU DAT rate with the following separated components:

• the average actual pool price in each TOU period in 1998 representing the cost of energy components in the TOU rates,

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

• TA Billings charges which pass through the TOU charges in the TA’s rates. The Board considers that actual pool price DAT customers should also see TA Billings charges which pass through the TOU charges in the TA’s rates. All DAT customers should see separate TA Billings and DISCO Services charges mirroring those charged under the fixed rate which would otherwise serve them. The Board considers that the “H” factor works well for the fixed TOU charge DAT option intended for customers who are able to shift their loads to off-peak periods. The response of such customers is unaffected by the variation in the actual pool price from forecast. However, for the actual pool price DAT customer, the Board recognizes that if the “H” factor is used, with no adjustments, the risk of an extended period of pool prices above forecast might be so large as to bias customers against the option of taking the actual pool price DAT. The Board considers that the actual pool 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 price DAT customers from any significant increases in the average levels of pool prices over the1998 prices used in the calculation of “H” (As set out in Section 2(a)(1), the actual 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 1998 actual pool price record, the adjustment should leave customers who choose the actual pool price DAT generally no worse off than customers who choose fixed price rates or TOU DAT. If the actual total UOV received by the DISCO during each billing month is used to calculate the monthly refund or credit due each actual pool price DAT customer, then the changes in the overall UOV would generally offset the changes in overall pool price level. Then, if pool prices move markedly higher, actual pool price DAT customers will not automatically be worse off than customers on fixed rates. DAT customers who do respond to the pool price will more likely be better off than customers on fixed rates. DAT customers must be allowed to respond to the hourly variation in pool prices without being overcharged because of the difference between forecast and actual average pool price. Therefore, the Board considers that the appropriate monthly adjustment per kWh billed in the month would be 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 is positive and benefits actual pool price DAT customers. Otherwise, when the adjustment is negative (i.e. pool prices are lower than forecast), a DAT customer might end up worse off than fixed rate customers even if the DAT customer were reducing load during high pool price periods. In the case of lower than forecast prices, the impact on the DISCO of providing the adjustment is minimal since the DISCO will likely have saved more than the amount of the adjustment through lower than forecast purchase costs for other customers. Also the DISCO will potentially benefit from the downward pressure on the cost of energy. In the case of higher than forecast prices the DISCO would pay the extra at any rate if all customers remained on fixed rates. Therefore, the Board directs TransAlta to design its actual pool price DAT rate with the following separated components:

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

• the fixed amount “H” charge calculated using the 1998 pool price record and 1998 total AE DISCO annual energy usage, and

• TA Billings charges which pass through the TOU charges in the TA’s rates. The Board considers that the viability of the DAT will be enhanced if a customer has the option to take all or only part of its service under the DAT rate. In other words, a customer must also have the option to take only a portion of its energy on the DAT after taking some set amount on another rate. The Board considers that TransAlta’s concern that rate stacking introduces administrative complexity is outweighed by the benefits provided by a viable DAT rate option. Therefore, the Board directs TransAlta to amend rate schedule 6800 to allow customers to take only a portion of their load under this rate. With respect to the eligibility for DAT and stacking, the Board considers that customers currently under interruptible and/or price responsive contracts must continue to honor their contracts. However, the Board accepts IPCAA’s position that that any load served under an Option 12 or Option 21 contract that is terminated, whether by agreement of the parties or at the direction of the Board, should be immediately eligible for the DAT. Also customers taking temporary energy (Rate 720/6600) qualify for firm service or DAT upon expiry of their contract as would any new customer. The Distribution Regulation (EU Act, section 31.6 (8)(9)(10)) requires that a DAT customer give six months notice of the effective date of the change if it elects to be billed pursuant to another tariff offered by the distributor. However, the Board considers that the risk to the DAT customer of inaccurate pool price forecasts is much reduced by the adjustment and stacking. Further, the Board considers it evident that a customer could choose to take a DAT rate in a low pool price season and revert to an averaged rate when pool prices are expected to be high, taking advantage



of seasonal price fluctuations to the detriment of the DISCO and/or other customers. Therefore, the Board considers it appropriate to direct that DAT rates include the provision that notice can be given only after a customer has been on the rate for six months. The Board will only shorten the notice period if the direct access customer satisfies the Board that financial arrangements have been entered into by the customer that compensate the distributor and its other customers for any costs resulting from the shorter notice period. (14) Partial Requirement Service C Rate 0820

In the Application TransAlta proposed to continue with a structure of standby rates as approved by the Board in Decision E94076. TransAlta proposed to withdraw existing Rates 820 and 830 and replace them with Rate 0820. Subsequent to its original filing TransAlta amended the Application to remove any differentiation between full service and partial service customers. TransAlta submitted that the removal of such differentiation is facilitated by the following characteristics of the proposed full service rates:

• there is an unbundling into generation and delivery components, • the generation charges are all energy related, and • the delivery charges have a fixed component which recovers the cost of local and

dedicated facilities for full or partial service customers. TransAlta therefore withdrew the proposed Rate 0820. Board Findings

The Board notes that the changes that TransAlta has proposed to its rates, such as unbundling its rates between generation and delivery, have effectively removed any differentiation between full service and partial service customers. The Board agrees that standby service will be appropriately priced by the full service rates which arise out of the refiling. Therefore, the Board finds TransAlta’s proposal to withdraw existing Rates 820 and 830 to be reasonable. (15) Wholesale C Rate 8100

Rate 8100 is a rate available to Municipalities that own and operate electric distribution systems supplying electric service to their residents. In the Application TransAlta proposed to close the rate to new customers. With respect to the structure of the rate TransAlta proposed to unbundle the rate into a Generation Service Charge and a Delivery Service Charge. TransAlta also proposed TOU differentiation for energy based charges. These charges would vary according to On-Peak, Shoulder, and Off-Peak pricing. The hours covered by the On-Peak and Shoulder periods would be seasonally differentiated as well.



No parties commented on Rate 8100. Board Findings

The Board notes that the changes TransAlta has proposed to the rate, namely unbundling and time of use pricing, are consistent with the changes proposed to many of the other rates. The Board finds that TransAlta’s proposed design of Rate 8100 is reasonable except that the Delivery Charge should be the TA Billings charge. In Section 3(a), the Board directed TransAlta to design rates so that:


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


The Board also directed TransAlta to include a table showing the revenue-to-cost ratios for each cost source (Energy Supply, TA Billings and DISCO Services) for each rate class. (16) Shared Use of Overhead Facilities C Rate 9100

In older residential subdivisions within TransAlta’s service area electricity is distributed through a system of overhead wires. The supporting structure for TransAlta’s distribution wires is a network of distribution poles. The distribution poles are owned by TransAlta. Where these distribution poles are in place and space is available on the poles, TransAlta has shared its poles with telecommunication carriers and cable television companies. In exchange for access to TransAlta’s distribution pole network, TransAlta levies a charge to recover a sharing of the pole costs. Previously this rate was negotiated between TransAlta and the cable companies and TELUS and was not submitted to the Board for approval. TransAlta has applied for approval of Shared Use of Overhead Facilities Rate 9100 (Rate 9100). Shaw Communications Inc. and The Canadian Cable Television Association (collectively the Cable Intervenors) opposed TransAlta’s Application with respect to Rate 9100 on jurisdictional grounds. TELUS also opposed the Application on the basis that approval of Rate 9100 is beyond the jurisdiction of the Board. In its submission TELUS limited its jurisdictional argument to what has been defined below as the constitutional issue; that as a matter of constitutional law provincial legislation cannot regulate a vital part of a federal undertaking.32 TELUS went on to comment on the substance of TransAlta’s proposed tariff. The FIRM Customers supported TransAlta’s Application.


32 TELUS Communications Inc., Intervenor Evidence Submission to AEUB, p.2


The jurisdiction issues raised by the Cable Intervenors were as follows:

Whether the Alberta Energy and Utilities Board has the constitutional jurisdiction to approve Rate 9100. (“the constitutional issue”) Alternatively, leaving aside the constitutional issue entirely, whether the Applicant was right in placing the charges contemplated by Rate 9100 before the Board at all (“the narrow issue”).33

Board Findings

Although framed somewhat differently, the Board considers the second issue raised by the Cable Intervenors to be a question of statutory interpretation, that is whether the Board has the authority to consider and approve, disapprove or vary the rate charged by TransAlta to cable companies (or telephone companies) for the shared use of TransAlta’s distribution power poles. The Board will deal with the question of its statutory jurisdiction first. Statutory Jurisdiction

The question the Board has been asked to consider involves an examination and interpretation of the Board’s jurisdiction. The Board’s basic powers to regulate the tolls of power utilities are found in the EU Act and the Public Utilities Board Act (PUB Act). While the relevant provisions of the statutory framework are lengthy, they are set out below for completeness. First the Board clearly has jurisdiction over an “electric utility” which is defined in section 1(1)(f) to mean:

(f) “electric utility” means

(i) a regulated generating unit,

(ii) a transmission facility, or

(iii) an electric distribution system,

that is used, directly or indirectly, for the public, but does not include

(iv) a generating unit not listed in the Schedule,

(v) a transmission facility owned by a municipality or a subsidiary of a municipality, other than the City of Edmonton, unless the municipality passes a bylaw under section 59,


33 Argument in Chief of Cable Intervenors dated 9 December 1998, p.2


(vi) an electric distribution system owned by a municipality or a

subsidiary of a municipality, unless the municipality passes a bylaw under section 59,

(vii) an arrangement of conductors intended to distribute electricity

solely on property of which a person is the owner or a tenant, for use solely by that person and solely on that property, or

(viii) a facility exempted by the Board pursuant to section 73(4);

Section 49(1) of the EU Act requires the owners of “electric utilities” to file tariff applications with the Board. It reads:

49(1) The owner of an electric utility shall prepare a tariff relating to the electric utility and apply to the Board for approval of the tariff.

“Electric utility” was previously defined to include “an electric distribution system.” “Electric distribution system” is defined in section1(1)(d) of the EU Act as follows:

“electric distribution system” means the plant, works, equipment, systems and services necessary to distribute electricity in a service area, but does not include a generating unit or a transmission facility;

As TransAlta operates an electric distribution system, it is an electric utility as defined in the EU Act and it must file for approval of its tariffs pursuant to section 49(1) of the EU Act. Additional power for the Board to act in respect of tariffs for the attachment by cable television operators and telecommunication companies to TransAlta’s distribution poles is found in section 88 of the PUB Act:

88 When it is in the public interest or when, as a means of saving expense, it is in the interest of any owners of public utilities that there be a joint use of poles, conduits or equipment or other means of distribution, the Board may, after notice to all parties concerned, in cases where it is practicable, order the joint use and declare the terms thereof, and by the order or subsequent order make any provisions necessary for the convenient and effectual carrying out of the work, and for the operation of the services by means of the equipment so to be jointly used.

The overall powers of the Board are strengthened by the general supervisory powers over public utilities found in subsections 28(1)(a) and (2) and section 29 of the PUB Act: Decision U99035 Page 126 10 August 1999


28(1) The Board has all the necessary jurisdiction and power (a) to deal with public utilities and the owners thereof as provided in

this Act; … (2) In addition to the jurisdiction and power mentioned in subsection (1), the Board has all necessary jurisdiction and powers to perform any duties that are assigned to it by statute or pursuant to statutory authority. 29 In matters within its jurisdiction the Board may order and require any person or local authority to do forthwith or within or at a specified time and in any manner prescribed by the Board, so far as it is not inconsistent with this Act or any other Act conferring jurisdiction, any act, matter or thing that the person or local authority is or may be required to do under this Act or under any other general or special Act, and may forbid the doing or continuing of any act, matter or thing that is in contravention of any such Act or of any regulation, rule, order or direction of the Board.

The Cable Intervenors argue that the definition of “electric utility” relates solely to the generation, transmission and distribution of electricity. In their view the costs for sharing support structures are not related to the distribution of electricity. In the result those costs should not form a part of a tariff filed by an electric utility pursuant to section 49. TransAlta points out that the definition of “electric distribution system” expands the definition of “electric utility” to clarify that an “electric distribution system” includes the facilities necessary to distribute electricity. As a result TransAlta concludes that the fee for joint use of distribution poles is properly before the Board. It is clear to the Board that the statutory language cannot be limited as the Cable Intervenors propose and that distribution poles are included in the definition of “electric distribution system.” As such the costs related to those distribution poles are properly the subject matter of a tariff application to the Board. A second reason not to limit the Board’s powers in the narrow way advocated by the Cable Intervenors relates to the key principles of statutory interpretation that the Board utilizes in delineating its jurisdiction. In the Board’s view the specific jurisdiction conferring sections should be examined in light of the statutory scheme as a whole, the purpose of the legislation, the reason for the Board’s existence, the expertise of the Board and the nature of the problem before the Board. When taken as a whole the provisions set out above from the EU Act and the PUB Act strengthen the Board’s interpretation of “electric distribution utility” as they indicate a clear legislative intention to confer significant power in the Board over power utilities and their rates. In particular section 88 of the PUB Act confers upon the Board specific authority to order the Decision U99035 Page 127 10 August 1999


joint use of poles and declare the terms for such sharing. The statutory scheme promotes the public policy objective of encouraging the sharing of existing support structures and provides a regulatory mechanism for reviewing the appropriateness of the rates charged by the electric utility for use of its poles. The Board is therefore of the view that it has statutory jurisdiction to consider, approve, disapprove or vary Rate 9100 filed by TransAlta. The Board would like to comment on a contention of the Cable Intervenors that the Board does not have jurisdiction over everything TransAlta does simply because it is an electric utility. In particular it is argued that because all TransAlta is doing is leasing part of its facilities to cable television operators, it need not apply for approval of the rent as a tariff item. The analogy is made to a sublease of its office space to a cable television operator.34 Although not cited by any of the parties, this issue was addressed by the Manitoba Court of Appeal in Greater Winnipeg Cablevision Limited v. The Public Utilities Board and Manitoba Telephone System, [1979] 2 WWR 82 (Man. C.A.). In that case, the Court considered whether the Manitoba Public Utilities Board had jurisdiction to regulate the amount of rent charged for coaxial cables by public utilities. The Court stated at p.87:

It is common ground that MTS is a public utility within the definition, with respect to its telephone and telegraph services … It does not necessarily follow that everything done by MTS is subject to the regulatory supervision of the board. It is possible for an undertaking to be a public utility as defined in the Act for some purposes and not for others.

The Court went on to consider the specific provisions of the Public Utilities Board Act (Manitoba) and the Manitoba Telephone Act and concluded that those provisions did not give the Board the jurisdiction to regulate coaxial cables. The Board recognizes that the Court concluded that a tribunal does not have jurisdiction in all cases over the action of a public utility simply because it is a public utility as defined in the tribunal’s enabling legislation. However the Court does look to the relevant statute to determine the scope of the tribunal’s jurisdiction over a public utility. In our case, as set out above, the Board has concluded that the relevant statutory provisions provide direct statutory authority over the tariff for the joint use of poles. Furthermore the Board considers that the various provisions of the EU Act and the PUB Act must be interpreted in light of one of the purposes of the Board; the protection of ratepayers against the monopoly power of the utility. Therefore the Board is of the view that the Board’s broad general powers provide it with the ability to regulate the tariff charged by TransAlta to




cable or telephone operators, to the extent that there is an impact on ratepayers. To the extent distribution poles, an asset of the utility, are used by any party at a less than appropriate charge, ratepayers are subsidizing that party and the Board has the jurisdiction and obligation to set that charge to minimize or eliminate the effect on ratepayers. Constitutional Jurisdiction

The Cable Intervenors challenge the constitutional jurisdiction of the Board to approve Rate 9100.35 This raises a procedural issue. This is recognized by the Cable Intervenors when they caution the Board that it may not be able to make a decision on its constitutional jurisdiction without compliance with the Judicature Act, R.S.A. 1980, c.J-1.36 The Cable Intervenors indicate that subsection 25(2) of the Judicature Act may be applicable to this case.37 The notice provisions of section 25(2) are as follows:

When in a proceeding a question arises as to whether an enactment of the Parliament of Canada or of the Legislature of Alberta is the appropriate legislation applying to or governing any matter or issue, no decision may be made on it unless 14 days’ written notice has been given to the Minister of Justice and Attorney General for Alberta and the Attorney General for Canada.

The Cable Intervenors have not complied with section 25(2). It appears that Courts will not attempt to deal with a constitutional question if the notice procedure has not been followed. (See for example, Northern Telecom Ltd. v Communications Workers of Canada [1980] 1 S.C.R. 115; Broddy v Dir. of Vital Statistics, [1983] 1 WWR 481 (Alta. C.A.)) The Board has assumed that the procedural section applies to it as, in its view, this position serves the public interest by ensuring that a constitutional issue is fully argued by the litigants and the Attorney’s General for Canada and Alberta should they so choose. Even if the Board is wrong in its view it would, as master of its procedure, normally require that this procedural notice be provided. Where no notice is provided however due to the oversight of the party raising the issue, the Board considers that it could properly refuse to deal with the constitutional issue and deal only with the other issues raised by the application. Authority for that proposition is found in the Broddy decision (supra) where Kerans J.A. for the Court states at p.491:

It was also argued for the appellant that he has been deprived of his liberty to marry freely, and he invokes s.7 of the Canadian Charter of Rights and Freedoms, Constitution Act, 1982 Pt.1. But this issue is not properly before us. There is

35 Argument in Chief of Cable Intervenors dated 9 December 1998, p.2 36 Argument in Chief of Cable Intervenors dated 9 December 1998, p.10




nothing to indicate that written notice in this regard …. has been given to the Attorney General for Canada or the Attorney General for Alberta. In my view, a proposal to read down in light of the Charter is also an attack on the validity, and s.25(1) of the Judicature Act, R.S.A. 1980, C.J.-1, applies. The practice of this court is to require strict adherence to these provisions. Accordingly, I will not deal with the Charter issue.

In these circumstances however the Board will decline to adjudicate on the constitutional issue raised even though the Cable Intervenors failed to comply with the notice requirements of the Judicature Act. The main reason for this approach is, in the Board’s view, this may be the first case where a constitutional issue has been raised before the Board in the absence of notice. Instead the Board will defer consideration of the constitutional question until the Cable Intervenors have provided the appropriate notice. The Board will reconvene to entertain additional submissions, either orally or in writing from the Attorneys General. Should the Attorneys General choose not to intervene, the Board will make its determination on the basis of the material previously filed. (b) Options and Riders Summaries

(1) Option A C Primary Service Credit

Option A, Primary Service Credit, formerly Option 1, is intended for customers where the cost of customer-related supply facilities is less than TransAlta’s investment. TransAlta proposed to set Option A, at $0.35 per kW of capacity per month for those customers who provide and maintain their own transformation. Option A would be available for a minimum period of 12 consecutive months to services:

• supplied under a satisfactory contract on the General Service Rate or the Large General Service TOU Rate,

• normally metered at a primary voltage with the customer providing the transformation to the customer’s utilizations voltage,

• with a normal power requirement of not less than 1,000 kW, and • where the total cost of the required customer-related supply facilities (including any

customer supplied transformation) is less than TransAlta’s investment. TransAlta also proposed that if the customer’s service is equipped with secondary metering the metered demand and metered demand energy consumption would be increased by one per cent to reflect transformer losses.


4. INDIVIDUAL RATES, OPTIONS AND RIDERS (b) Options and Riders Summaries TRANSALTA 1996—Phase II


TransCanada

TransCanada requested clarification from TransAlta with respect to availability item 4 noted above, and its applicability to the Primary Service Credit. TransAlta stated that the Primary Service Credit would only apply where TransAlta actually incurred a saving through not having to invest in the customer supplied transformer. TransCanada recommended that, to ensure clarity, the wording in Item 4 should be revised to state “where the total cost of the required customer-related supply facilities (after deducting the costs of customer supplied transformation paid for by the customer) is less than TransAlta’s investment.” TransCanada noted that TransAlta’s basis for the Option A credit would be the avoided cost of transformation. This means that the $0.35 per kW credit will apply where TransAlta would be willing to make an investment but the customer installed his own transformation so that TransAlta would not be required to make that investment in transformation. TransCanada explained to TransAlta that the Primary Service Credit should be larger if a customer stepped down from a higher voltage such as 240 kV rather than the 25 kV used as the basis for the calculation of the credit. TransAlta responded that those customers would qualify for Option B or the Unused Investment Credit. However, TransCanada submitted that there was nothing in either Option A or Option B that stated that Option B would apply to customers served at 69,000 volts and above. TransCanada submitted that Option A should be available to any customer who meets the qualification of the Option, the key condition being that, TransAlta clearly incurred savings by not investing in the transformation paid for and owned by the customer. TransCanada argued that, customers not interested in long term contracts, may be precluded from receiving appropriate credits for the savings, for stepping down from high voltages, that they bring to TransAlta. In doing so, TransAlta has avoided the fact that stepping down from higher voltages than 25 kV resulted in higher incurred savings than when stepping down from 25 kV for the same MVA of capacity. TransCanada noted that these higher incurred savings should be recognized in Option A. TransCanada recommended that TransAlta modify Option A to recognize the different benefits incurred by customers stepping down from higher voltages than 25 kV to voltages below 25 kV. With regards to the one per cent loss used in Option A, TransCanada noted TransAlta’s statement that this was a fairly standard number and no analysis was performed in Phase II to verify its accuracy. TransCanada also noted that, when TransAlta was questioned about the possibility for such analysis, TransAlta responded that such an analysis was not necessary since a customer could find out about transformation losses from a transformer supplier. TransCanada noted that, when questioned, TransAlta indicated that they would be prepared to adjust the increase should a customer find out specific information in relation to a particular transformer. TransCanada requested that TransAlta be directed to amend Option A to include the condition that at the customer’s request, the loss percentage of one per cent may be replaced with the



actual transformer loss data provided by a transformer supplier for typical loading conditions in relation to the specific transformer. Position of TransAlta

In reply to the arguments submitted by TransCanada, TransAlta stated that load size not voltage level would recognize economies of scale. Therefore, Option A credit should be segregated by customer size rather than by voltage level. TransAlta also stated that the Option A credit would be available to customers between 1,000 kW and 3,000 kW with the Option B credit being appropriate for customers above 3,000 kW. Option B would be a better method of sending price signals back to the customer and would also be a higher credit as well. TransAlta stated that all customers over 75 kW were required to have an appropriate contract in place before service was provided or an investment was made. Therefore, the suggestion by TransCanada that there was inequity between Option A and Option B regarding the need for satisfactory long term contracts under Option B, was invalid since customers under both Options require satisfactory long term contracts before service is required or an investment made. With regard to the issue of transformer losses as addressed by TransCanada, TransAlta stated that metered readings should be adjusted by one per cent where the customer service was equipped with secondary metering to compensate for transformation losses. Regarding the utilization of actual transformer loss data if requested by the customer as recommended by TransCanada, TransAlta noted that TransCanada did not provide grounds for the basis of its recommendation and the recommendation should be rejected. TransAlta stated that the previously approved one per cent losses compensation was a reasonable estimate of actual transformer losses. Board Findings

The Board notes that TransCanada had three recommendations regarding TransAlta’s proposed Option A. The Board considers that TransCanada’s suggested change in wording to availability item 4 is relatively minor and does not significantly clarify the clause. Therefore the Board will accept TransAlta’s proposed wording of the fourth availability item. With respect to the recommendation that Option A be modified to recognize the benefits from stepping down from voltages higher than 25 kV, the Board agrees with TransCanada that stepping down from high voltages should provide a higher cost saving to TransAlta than stepping down at the 25 kV level. To the extent that there is a greater saving, this should be reflected in a higher primary service credit to customers. The Board does not have sufficient information before it to assess what an appropriate primary service credit should be at higher voltages than 25 kV. The Board also does not have information to determine whether the proposed primary service credit will have to be revised if it is to be used only for customers maintaining their own transformation from the 25 kV level. Therefore the Board will approve the Option A–Primary Service Credit as proposed at this time. However, the Board directs TransAlta



to provide, at the time of its next Phase II application, a primary service credit which provides appropriate credits for various voltage levels. TransCanada also questioned the one per cent adjustment to reflect transformer losses when secondary metering is used. The Board notes that the one per cent is used as a reasonable estimate of actual transformer losses. The Board is not satisfied that a study of transformer loss data done at one point in time will provide a sufficient indication of transformer losses over time. The Board considers that the one per cent adjustment, represents a reasonable estimate of actual transformer losses for all customers on Option A. (2) Option B C Unused Investment Credits

TransAlta proposed to eliminate Option B credits, Unused Investment Credit Option, formerly Option 10, for the first 1,000 kW of unused investment. There would be no change to the level of credit at $2.15/month for each eligible kW of unused investment. TransAlta stated that its proposed changes to the Unused Investment Credit result from its proposal to streamline its investment policy included in its Terms and Conditions of Electric Service. The Unused Investment Credit Option would be available to Large General Time-of-Use Service, Transmission Service, Real Time pricing, and DAT customers

• supplied under satisfactory long term contracts, • with contracted minimum demands of 2,000 kW or greater, and • where the total cost of the customer-related supply facilities (including prepaid

operation and maintenance) is less than TransAlta’s investment. The kW of Unused Investment was equal to TransAlta’s investment less the total cost of supply facilities, divided by the average level of TransAlta’s investment per kW as set out in the Terms and Conditions of Electric Service. Customers who would like to increase the kW of Unused Investment for an existing service are to provide TransAlta with written notice one year in advance. For customers who give notice to decrease the kW of contracted demand and kW of Unused Investment, TransAlta would have the right to reduce the Unused Investment amount prior to the end of the period. Position of the Intervenors

TransCanada

TransCanada noted that the Option B credit was only available to customers who were supplied under a satisfactory long-term contract. For those customers who were concerned about



deregulation and its implications, signing a long-term contract to obtain an Option B credit may not be desirable. IPCAA

IPCAA submitted that historically no incentive was given for customers to own their own substation since no rate credit was given for service at transmission voltage, but this should be changed. IPCAA stated that even though TransAlta had made efforts to encourage the most efficient planning of transmission facilities by distinguishing distribution-level Rate 6300 from transmission-level Rate 6400, this change should not be limited to new customers only. IPCAA stated that existing customers should be allowed to become transmission-level users when they could acquire the substation, a change that TransAlta has so far been unresponsive to. IPCAA recommended that existing and new customers should be permitted to take service at transmission level voltage and have the resulting cost savings recognized in their rates. IPPSA/SPPA

IPPSA/SPPA stated that TransAlta did not provide any evidence to support its proposed modifications to Option B, Unused Investment Credits or to justify limiting the applicability of Option B. Position of TransAlta

TransAlta did not propose to change the level of the investment credit for Option B. TransAlta is eliminating the Option B credit for the first 1,000 kW of unused investment for new customers to offset the increased investment available to customers over 3,000 kW. TransAlta noted that its proposed investment policy removes the discontinuity which formerly existed at 3,000 kW. In response to IPCAA’s recommendation that customers be allowed to acquire their substations in order to become “transmission-level” users, TransAlta stated that the reason IPCAA gave to substantiate their recommendation was incorrect since TransAlta, for many years, had made Option 10, Unused Investment Credits, which is the proposed Option B, available to customers who declined TransAlta’s investment and owned their own substations. In addition, TransAlta stated that Option 1, Primary Service Credit has also been available to customers for many years. TransAlta stated that IPCAA’s statement regarding differentiation by voltage level was incorrect. TransAlta stated that the distinction between Rate 6300 and Rate 6400 was based on customer load size, as indicated on the rate sheets, not on the connection voltage distinction as stated by IPCAA. TransAlta stated that they have taken reasonable steps to allow rate differentiation by customer size and have provided customers with the opportunity to reduce their bills by owning their own substations. TransAlta noted that IPCAA’s plan will justify the expropriation of substations and



bill reductions for select customers. TransAlta stated that IPCAA’s recommendation should be rejected. Board Findings

The Board notes that TransAlta amended the eligibility of Option B as a result of its change in investment policy levels. TransAlta has changed its investment levels to move towards the point where 80% of customers do not have to pay a customer contribution. The Board notes TransCanada’s concern that Option B should not be limited to customers who sign long-term contracts. However the Board considers it reasonable that TransAlta will only pay Unused Investment Credits to customers who will remain on its system for a sustained period of time, as a means of protecting its investment. The Board is satisfied that TransAlta’s proposed Option B is reasonable in conjunction with the changes made to its investment policy. Therefore the Board approves Option B as proposed. (3) Option C C Idle Service Option

TransAlta proposed that Option C, Idle Service Option, would be billed to Idle Service customers as follows:

• Idle Residential services are billed a Basic Monthly Charge of $14.00,and • Farm, Oil and Gas, Small General and General Services customers are billed on the

greatest of: • the highest deemed Metered Demand in the 12-month period including and

ending with the billing period, • the Minimum Demand as determined by application of the Terms and

Conditions of Electric Service, or • the Rate Minimum.

The Idle Service Option would be available to disconnected customers who request that TransAlta leave the electric supply facilities in place. Idle service customers would not normally be required to pay the cost to disconnect and reconnect the service. TransAlta proposed to charge the idle service charge to achieve consistent application of charges between Farm, Oil and Gas and General Service Rates. Position of the Intervenors

IPPSA/SPPA

IPPSA/SPPA stated that TransAlta’s proposal to move from a flat monthly idle service charge to effectively being billed on a 12 month ratchet when a customer goes idle will result in significant price increases even though TransAlta indicated that this change will not result in a rate increase. Decision U99035 Page 135 10 August 1999


IPPSA/SPPA noted that there was no evidence regarding the number of existing idle service accounts or how many were added each year. Therefore, the impact of incremental revenues to TransAlta from oilfield accounts moving to idle service could not be predicted. IPPSA/SPPA noted that the proposed change was clearly significant and material and a reasonable increase should be considered if TransAlta believed that the current charge of about $57 per month would not be adequate to recover wire charges while customers were not using the electric distribution system. IPPSA/SPPA suggested an extension of the current flat rate charge for idle service. Option C should be redesigned to phase in the proposed cost increase should TransAlta’s proposal be accepted. IPPSA/SPPA stated that the forecast revenue from Option C should be determined and included as oilfield revenue. Until such time, IPPSA/SPPA stated that Option C should continue as a flat rate charge of $57 per month. IPPSA/SPPA stated that, if a customer elected Option C, the account should be billed on the flat rate charge. However, if a customer elected to move off Option C within 12 months, then the account should be adjusted such that the customer was never on Option C. These changes could be accomplished by removing clause 2a from the Option C rate schedule and adding a clause to dissuade customers from moving to Option C for periods of under 12 months. IPPSA/SPPA stated that TransAlta’s proposed policy would allow any service under 2,000 kW to be cancelled after one year. IPPSA/SPPA noted that no contract was required and no contract terms were proposed for small oilfield accounts under 75 kW. IPPSA/SPPA further stated that if TransAlta’s proposed Option C is accepted, customers would have the choice of canceling the service and paying nothing or paying demand charges for an additional 12 months under Rate 4100, Rate 4500 or Option C. If the customer chose to cancel the service, TransAlta may be disconnecting and reconnecting a larger number of accounts under the proposed Option C which would eventually result in overall higher costs. IPPSA/SPPA noted that under the proposed Terms and Conditions clause 17 item 4, a customer could reconnect at no cost if the service had been disconnected for more than 14 months where the distribution assets serving an account were not salvaged. Where the distribution assets were salvaged, the customer could request service and would be obligated to pay for a minimum of 12 months. If the service was expected again within 12 months or less, the existing policy is such that the customer will pay as if no service disruption occurred. IPPSA/SPPA stated that idle service is a service that oilfield customers expect and have built into their decision making when selecting electric energy over an alternative. The existing policy of flat rate charges for idle service accounts should be maintained to minimize costs to oilfield customers and to provide some level of flexibility. IPPSA/SPPA submitted that TransAlta’s proposed Option C should be rejected. Decision U99035 Page 136 10 August 1999



TransAlta indicated that they have outstanding investment in idle services and it would be inappropriate to waive the one-year historical billing requirement for those services which become idle and for which the idle services option was chosen. TransAlta stated that IPPSA/SPPA’s submission related to Idle Service in the context of the Oilfield Service, whereas TransAlta had designed Idle Service to be suitable and consistent for all services except those governed by a specific contract. TransAlta stated that IPPSA/SPPA had not put forward a reasonable alternate proposal to modify the idle service charge. TransAlta stated that the cost causation relationship to the demand charge for Idle Service was the same as that for the 100% ratchet for demand charges for 12 months. TransAlta noted that, with the new industry structure and the unbundling of rates, demand charges now apply principally to dedicated and local supply facilities which are sized according to a customer’s peak demand. If these facilities are sized to a customer’s peak, the cost is not reduced if the customer’s demand is idle for a period of time. TransAlta submitted that its proposal for Idle Services would fairly recover the costs of providing that service and the proposed changes would reduce any intra-class subsidy between idle service and active service customers. Board Findings

The Board notes that TransAlta designed the Idle Service Option to be applied in the same manner for farm, oil and gas, small general and general service customers. The Board notes that some oilfield customers may be faced with a large rate increase due to the pricing of this service to reflect costs. However, the existing idle service charge of $57.00 per month is not cost reflective. Therefore, the Board cannot support the continued use of this rate as proposed by IPPSA/SPPA. The Board also notes that Idle Service is just one of the services oilfield customers use from TransAlta’s rate offerings. While in this instance increased costs result for some oilfield customers the Board notes that oilfield customers will likely receive a greater than average decrease for their rate class. The Board considers that demand charges in most rates will now apply principally to dedicated and local supply facilities which are sized according to a customer’s peak demand. If these facilities are sized to a customer’s peak, the cost is not reduced if the customer’s demand is idle for a period of time. Therefore, the Board considers it appropriate that a customer be required to continue to pay its demand charges during a period of idle service. The Board recognizes that a customer may choose to end service and then be required to pay charges when they reconnect, if that is its most economical option.



The Board therefore approves TransAlta’s Option CCIdle Service as proposed. (4) Option D C Flat Rate Option

TransAlta proposed to continue Option D, Flat Rate Option for customers with minimal, accurately predictable monthly energy consumption. The Flat Rate Option would be available to services billed on the Small General Service or Oil and Gas Service Rate, using an estimated kW of Capacity and an estimated monthly kilowatt hour consumption. The Minimum kW of Capacity is 1 kW and the minimum charge would be $14.00 per month. The Flat Rate Option would be applied for a minimum period of 12 consecutive months. Board Findings

The Board notes that there was no discussion of Option D. The Board considers that Option D should be continued as proposed with any changes, if necessary due to the Board’s cost of service and rate design findings. (5) Option E C Deemed Demand Option

TransAlta proposed to continue to phase out Option E, Deemed Demand Option. The Deemed Demand Option would be available for a minimum period of 12 consecutive months to the following:

• apartment house common use areas such as halls and basements, utility rooms, car stalls, etc., where all the apartments are individually metered and billed as residential services;

• travel trailer parks with widely varying seasonal requirements and where service is taken by the proprietor on a bulk basis through one metering point;

• single family residences where there is more than 1,000 watts of non-residential load installed for use in connection with a small private business, consuming less than 3,000 kWh per month in total and served through the same meter; and

• churches, parish halls and non-profit community-operated halls and clubs, with an anticipated demand of 50 kW or less.

With the exception of the above, the Deemed Demand Option E would not be available to:

• private clubs, fraternal society clubs or any organization or society where membership is restricted;

• sports grounds, parks, golf clubs, seasonal lighting (skating rinks), ice plants, • scout or guide halls; or • convents, seminaries, bible schools and colleges.

A Deemed Demand Option customer’s bill will be calculated on the Small General Service Rate 4100 with the Metered Demand deemed equal to 1 kW for each 170 kWh or portion thereof.



Option E was formerly TransAlta’s Option 4 with the proposed changed that the metered demand will be deemed equal to 1 kW for each 170 kWh of energy consumption. Board Findings

The Board notes that no intervenor addressed this issue. The Board accepts TransAlta’s proposed Option E as reasonable given that this Option is continuing to be phased out. (6) Option F C Planned Interruption Credit

The Option F, Planned Interruption Credit, as proposed by TransAlta would be available:

• to customers supplied under satisfactory long-term contracts wherein TransAlta has the right to require the customer to shed a portion of the customer’s load upon request,

• to services with an approved TOU meter, and • for a minimum period of five consecutive years.

Option F would be closed to new customers. Customers currently on Option F will continue to receive interruptible credits until the agreement expires on 31 August 2000. In exchange for the credits, TransAlta will continue to direct these customers to remove their Option F load from the system when there is a shortage of generation. TransAlta proposed that, as there is no longer sufficient information to deem a generation shortage, an hourly pool price of a minimum of $40/MWh would be used as a proxy to determine a generation shortage. The amount of the credit depends on the maximum number of interruptions hours per year, the duration of the interruption, and the advance notification period as outlined in the table below.



Planned Interruption Credit Table

($/kW/Month) Notification $ $ $ Period Based on 200 hours of 1.80 2.13 – 4 hr Cumulative Interruption per year 2.13 2.47 – 1 hr (Maximum of 50 calls per year) 2.33 2.67 – 30 min Based on 400 hours of 2.34 2.71 2.78 4 hr Cumulative Interruption per year 2.71 3.07 3.22 1 hr (Maximum of 100 call per year) 2.93 3.29 3.37 30 min Based on 800 hours of 3.50 4.00 4.10 4 hr Cumulative Interruption per year 4.00 4.50 4.60 1 hr (Maximum of 200 calls per year) 4.30 4.70 4.80 30 min Interruption Duration Hours: 4 8 12

Option F also prescribes non-compliance penalties applicable to customers that fail to comply in duration and magnitude with TransAlta’s request for interruption. The issues raised by Intervenors regarding Option F relate to the following questions:

• Does the Board have jurisdiction over these contracts? • Should Option F contracts be terminated and, if yes, should these customers be allowed

to take energy under a firm rate? • Should Option F contracts remain with TransAlta as applied for? • Should the administration of Option F contracts be transferred to the System Controller,

the TA , the Power Pool, or other entity? • Should the administration of Option F contracts remain with TransAlta but customers be

allowed to buy-through their interruption? • Should the credits/penalties be modified and, if so, by how much?


TransAlta stated that it decided to terminate Option 12 contracts because it no longer had a role for capacity planning in a competitive world and, in August 1995 TransAlta notified customers that all Option 12 contracts would be terminated by 31 August 2000. However, TransAlta indicated it worked closely with IPCAA and developed the following three options for Option 12 customers to choose from:

• continue to stay on embedded rate 790 and receive Option 12 credit for interruptions until termination in 2000,

• terminate Option 12 agreements prior to 31 December 1996 and revert to a non-interruptible rate, or



• move to Rate 780/Option 21.

TransAlta indicated that IPCAA and its members, including the ACD companies, were involved in the development of the above options and were aware that TransAlta anticipated increased interruptions to Option 12 customers after 1995 as the surplus capacity was diminishing and no new generating units were planned. TransAlta stated that customers who elected to stay in Option 12 were aware the new electric industry structure contemplated that new generation would be constructed in response to competitive market forces driven only by price. Therefore, TransAlta implemented a price policy for calling down Option 12 customers based on a pool price trigger of $40–$42/MWh. TransAlta submitted that, under the new electric industry structure, shedding Option 12 by pool-price trigger was a reasonable approach as TransAlta no longer had visibility to identify a generation shortage and the use of a pool-price trigger was the only way to emulate how Option 12 customers were required to curtail load before 1996. TransAlta submitted that it managed Option 12 contracts in an appropriate manner in a rapidly changing environment. However, TransAlta admitted that Option 12 loads were not used to their maximum effectiveness due to TransAlta’s adherence to the policy of interrupting load only when pool prices reached $40–$42/MWh. Adherence to the $40–$42/MWh pool price policy, combined with the fact that pool prices were increasing faster that anticipated, resulted in some Option 12 loads being interrupted for their maximum annual number of hours within the first nine month of the year. For this reason, TransAlta applied to the Board to change the policy such that Option 12 loads would be called to interrupt, at TransAlta’s discretion, when the pool price reached a minimum of $40/MWh. TransAlta indicated that the requested change in policy would allow it to:

• manage Option 12 effectively, • minimize gaming of a visible pool price trigger by Option 12 customers, and • minimize possibility of marketers/importers gaming the market with the knowledge that

Option 12 loads are always bid at a preset price.

TransAlta emphasized, however, that none of the Option 12 customers have ever been interrupted more than allowed for by the contract terms, even-though the current situation is such that surplus is at an all time low with 1998 being the first year in recent history that Alberta had shortages of supply resulting in firm load shed. TransAlta submitted that, given the move to a competitive environment, the use of a trigger based on pool price is still the best and only means to emulate a supply shortage. TransAlta explained that using a minimum pool price trigger greater than the unit obligation price (UOP) of regulated units ensures that Option 12 loads are called to interrupt only prior to firm load being curtailed and this is consistent with the manner in which Option 12 loads were called to interrupt prior to 1996. TransAlta also explained that, a minimum pool price trigger, rather than a fixed trigger, gives TransAlta sufficient latitude to ensure that the contractual maximum number of Decision U99035 Page 141 10 August 1999


hours of interruption will not be reached before the end of the year. TransAlta disagreed with the ACD’s suggestion that the pool price trigger should be set at $999/MWh as such a high trigger price would increase the risk of firm load being curtailed. TransAlta explained that by the time the pool price reached $999/MWh the System Controller is already in the process of shedding firm load. With respect to the ACD’s suggestion that the administration of Option 12 contracts be transferred from TransAlta to the System Controller, TransAlta submitted that there is no evidence as to the feasibility, practicality, or general support for this idea. In the absence of a workable proposal to shift administration of Option 12 contracts, the Board should reject calls of ACD/IPCAA to have contracts terminated or shifted to the System Controller. However, TransAlta advanced a new proposal in Reply Argument recommending that the Board establish a framework for a negotiated settlement between TransAlta, all interested parties, and the System Controller. The negotiations would be aimed at finding a method where the System Controller makes the determination when Option 12 is to be curtailed, then the System Controller would advice TransAlta who would notify Option 12 customers to curtail load. TransAlta submitted it would support such a settlement on condition that:

• the method used by the System Controller emulates the method by which Option 12 were directed to shed load prior to 1996,

• all parties sign the negotiated settlement, and • it must apply to all Option 12 load shed directives.

TransAlta suggested that the Board set a schedule requiring the settlement, if reached, to be signed by 1 March 1999 so as to enable the Board to give effect to the results of the settlement by 1 April 1999. TransAlta stated that there is no evidence on the record to support the argument of TransCanada that the Board should reduce non-compliance penalties. It explained that any reduction in penalties would reduce the incentive to comply, increasing the risk of firm load sheds. Furthermore, TransAlta also took issue with the proposal to have the System Controller or the Power Pool establishing and enforcing non-compliance penalties as neither of these may have any interest in accepting these responsibilities nor is there any legal basis for having them discharge these responsibilities. Therefore, TransAlta submitted that the proposed non-compliance penalties are appropriate and that any proposal to reimburse past penalties would be inappropriate. TransAlta submitted that Option 12 customers should not be allowed to move back to standard embedded rates without being interruptible, as TransAlta does not have sufficient hedges to cover Option 12, 21, or Temporary Energy. Finally, TransAlta submitted that Option 12 agreements were signed in good faith, have been administered in good faith and should be adhered to in good faith by both parties for the life of



the agreements. Therefore, TransAlta requested final approval of amended Option 12 and final approval of Option F with a trigger of a minimum of $40/MWh. Position of the Intervenors

FIRM Customers

The FIRM Customers indicated that the ACD companies are bidding together as one single group in response to the TA’s request for proposals. Therefore, the FIRM Customers were concerned with the ACD having possible market power on the interruptible load market given that the ACD represents approximately two thirds of the total Option 12 load. The FIRM Customers submitted that, before the Board considers releasing Option 12 from their contracts, the Board must be sure that the alternatives being offered are at least equally beneficial to customers as the existing arrangement. In this regard the FIRM Customers pointed out that existing contracts have known credit levels and visibility while interruptible market proposals are confidential. Therefore, the FIRM Customers were concerned that this would make evaluation very difficult and submitted it cannot support termination of contracts unless it can be established that all customers would be better off by canceling the contracts. However, the FIRM Customers were prepared to leave the evaluation to the Power Pool or the TA on the basis they would do what is best for all customers. The FIRM Customers also submitted that, if the Request For Proposals process is unsuccessful, the FIRM Customers would endorse placing the Option 12 call down directive in the hands of the System Controller as long as proportionate benefits and costs flow through to TransAlta-DISCO’s customers. However, if none of the above can be achieved, the FIRM Customers proposed that contracts should remain in place and should be administered in the manner proposed by TransAlta. The FIRM Customers indicated it does not support either the ACD’s proposal to buy-through their interruptions or the ACD’s suggestion that the interruptible credits be increased 10 times their current level. The FIRM Customers submitted that the buy-through proposal has the appearance of changing an interruptible contract into one similar to a self-curtailing, price responsive contract such as Option 21 and that the ACD’s proposal to receive credits 10 times the existing credits fails to address the fairness or equity of the contracts over the entire five-year contract period and previous years. The FIRM Customers also commented on alternative proposals advanced by TransCanada and Enmax. With respect to TransCanada’s proposal, the FIRM Customers submitted the following:

• All costs resulting from the transfer of control to the Power Pool should be the responsibility of all AIS customers. Any rate conversion cost for Option 12 should not be borne only by TransAlta DISCO customers.



• Non-compliance penalties have not been discussed in this proceeding nor is there any evidence that the Power Pool or System Controller have examined this issue or have any recommendation.

• Regarding applying non-compliance penalties to only a portion of the load, the FIRM Customers recommended no changes be made at this time.

• TransCanada’s suggestion to compensate customers for previous partial non-compliance would be an exercise in retroactive ratemaking, something this Board has rejected in the past.

With respect to Enmax’s proposal, the FIRM Customers submitted the following unless two conditions are satisfied, namely that incremental interruptible load is bid into the Power Pool or TA and such load provide enhanced value, it is of no benefit to TransAlta’s firm customers if existing Option 12 load is simply re-offered at new, higher prices and administered by parties other than TransAlta.

ACD

The ACD submitted that TransAlta’s treatment of Option 12 loads have been neither sensible nor fair in the new electric industry structure. The treatment of Option 12 loads is not sensible because other customers are not realizing the full value of reliability provided by interruptible loads and it is not fair because Option 12 customers are precluded from participating in markets where they can add more value to the system. The ACD submitted that TransAlta was using Option 12 loads to optimize its own interests, rather than using Option 12 only during shortages of generating supply. The ACD submitted that the long-term objective was to have a functioning demand side market and no interruptible contracts between a DISCO and its customers. In the near term, more interruptible load and more effective use of existing interruptible load are needed to minimize potential generation shortfalls. Markets for interruptibility should be encouraged. However, the ACD submitted that TransAlta’s proposed Option F did not address the need for more interruptible load in the province. The ACD stated that TransAlta mismanaged the use of interruptible load and it was doubtful that its proposal to use a pool-price trigger proxy would result in the best use of interruptible load in the future. In this regard, the ACD submitted that there was no evidence in these proceedings to suggest that the continuation of a fixed price trigger was appropriate or recommended. The ACD submitted that the evidence pointed to the desirability and preferability of suspending, terminating, or transferring the administration of contracts to the Power Pool. With respect to the issue jurisdiction, the ACD submitted that the Board jurisdiction in matters of which it had statutory authority cannot be either limited or inhibited by private contracts. Contracts that purport to govern matters within the Board’s jurisdiction are subject to approval, modification, alteration, etc, by the Board.



In summary, the ACD urged the Board to:

• terminate contracts, or • transfer ownership/administration to the Power Pool, or • allow Option 12 to buy-through their interruptible obligation, or • if the Board adopts TransAlta’s position, the Board should increase the credits as the

value of interruptible load has increased, The ACD suggested the increase in value should be about 10 times the current value.

With respect to TransAlta’s latest proposal, the ACD submitted that the proposal was improper given the absence of evidence or the opportunity for cross-examination. Nevertheless, the ACD submitted that TransAlta’s latest proposal to have the System Controller calling down interruptible loads was already before the Board, absent TransAlta conditions. Furthermore, the ACD submitted that with this latest proposal TransAlta was:

• seeking to enhance its ability to further its position respecting the circumstances under which Option 12 load is to be shed,

• introducing new elements of uncertainty by suggesting a negotiated settlement, • insisting that the settlement apply to all Option 12, thereby precluding the ACD or others

to participate in other markets, and • extending the time frame within the status quo is preserved.

The ACD recommended that TransAlta’s latest proposal be rejected. Enmax

Enmax recommended: • Option 21 and 12 contracts should be suspended provided that these customers bid in at

least as much power to the Request For Proposals process of either the TA or the Power Pool.

• All customers should pay for the incremental costs of the Request For Proposals process. • Only TransAlta DISCO customers should pay the cost of replacing Option 12/21 load

with hedged energy. • Interruptible load should be handled by the Power Pool or the TA.

Enmax submitted that Option 12 loads were now interrupted based on a price signal, rather than in response to generation shortages and that this has resulted in contract amounts been used up in the first seven months of the year. Enmax also submitted that if the Board decides to release Option 12 loads from their contracts, they should be treated as new firm load and no increase in hedge should be granted to TransAlta DISCO for these loads. Enmax maintained that TransAlta received greater entitlement shares due to its Option 12 load.



TransCanada

TransCanada submitted the following recommendations: • Option 12 non-compliance penalties should only be levied for that portion of the load that

is in non-compliance. • TransAlta should review the penalties proposed by the Power Pool and other utilities and

adopt fairer penalties or justify to the Board why this cannot be done. • Customers charged penalties in the past should be reimbursed for that portion of the

penalty relating to the portion of the load for which they were in compliance. • Authority for future call downs should rest with the System Controller or the Power Pool. • Customers should be able to transfer their Option 12 load to the System Controller or the

Power Pool, as long as current contractual conditions, such as maximum number of hours of interruption, advance warning notice, etc., remain at least the same as current contracts.

• TransAlta should only interrupt Option 12 load in cases of generation shortages or the calls to interrupt should be guided by the System Controller.

TransCanada submitted that the Option 12 non-compliance penalties were harsh. TransCanada was also concerned about the use of a pool price as a trigger for interruption, claiming that the use of an arbitrarily chosen pool price introduces an element of “incongruity” between actions and tariffs. TransCanada noted the evidence of IPCAA that TransAlta may be overcharging its customers on Option 12, forecasting to collect $19 million from customers but only paying out $8 million in credits. TransCanada submitted that TransAlta has gained the benefit of interruptible load through a reduction in the reservation payments due. TransCanada cited TransAlta’s testimony that it does not use Option 12 load as a price hedge but rather to emulate generation deficiencies. Therefore, TransCanada submitted that the System Controller, an independent body, should take over the call down function. TransCanada commented upon TransAlta’s assertion that the DISCO no longer has any role in generation planning. While conceding that the Board may have relieved the DISCO of its obligation to ensure sufficient generation capacity TransCanada argued that TransAlta’s Terms and Conditions of Service still required it to take reasonable precautions to guard against interruptions. TransCanada submitted that the very fact that TransAlta ran out of some interruptible resources after only nine months indicated that its policy was flawed and its actions imprudent. TransCanada also noted that TransAlta initially resisted the idea of transferring the responsibility for call downs to the System Controller and later offered to cooperate subject to certain conditions being met. In conclusion TransCanada reiterated its proposal to have Option 12 load transferred to the System Controller, citing the System Controller’s independence as offering the potential to provide a win-win situation for all parties.



IPCAA

IPCAA stated that if their contracts were terminated, Option 12 customers would be able to participate in initiatives of the Power Pool and the TA. IPCAA questioned how TransAlta could suffer financial harm if it is administering the contracts as it claims – solely to control power shortages. IPCAA pointed out the problem with Option 12 was that, with restructuring, the utility does not actually know when there is a generation shortage so it has resorted to using the pool price as a proxy for same. IPCAA claimed that TransAlta was interrupting Option 12 customers for reasons other than inadequate supply or operating reserves. IPCAA recommended that responsibility for call downs be transferred from TransAlta to either the System Controller or the TA so that the curtailable resource can be maximized for the benefit of all customers. TransAlta would simply act as a conduit for curtailment instructions from the System Controller and as a clearinghouse for the resultant credits. Alternatively the contracts could be assigned to the System Controller entirely. IPCAA did not see how TransAlta could suffer harm under either option. Board Findings

To decide on the issues regarding Option F (former Option 12) contracts, the Board must first address the issue of the Board’s jurisdiction to terminate, alter, vary, or transfer administration of these contracts. Jurisdiction

The Board, in discharging its mandate to fix just and reasonable tolls has the power and jurisdiction to deal with the question of rates in such a manner as it deems proper. If it is necessary for the Board to override contracts to set proper rates, that is within its jurisdiction. However, it is quite another matter to confer upon the Board the power to change a contract so as to give the contracted for rights and authority under that contract to a third party. That would be tantamount to holding that the Board can make new agreements between parties. This would be an extremely wide power and would have to be clearly set out in the Board’s enabling legislation. The Board could find no such power in the legislation. Therefore, absent agreement from all the parties, the Board cannot direct the assignment of contractual rights and responsibilities to a third party who was not a party to the agreement. Termination of Contracts

The Board has the authority to terminate these contracts if it considers that the rates set out in these contracts are unjust and/or unreasonable. In deciding whether or not the rates are unjust and/or unreasonable, the Board has to consider the effect of terminating these contracts not only on the contracting parties but also on the ratepayers in general. The Board agrees with the FIRM Customers that, before the Board considers releasing Option 12 from their contracts, the Board must be sure that the alternatives are at least equally beneficial to customers as the existing arrangement. The Board also agrees with the FIRM Customers’



submission that the alternatives, namely the offering of interruptible load to the Power Pool’s Request For Proposals process or any other such a process, are confidential processes and that makes the evaluation of whether or not the alternatives are better than the status quo difficult. However, during the hearing, two important points became very clear:

• if Option 12 contracts are terminated today, the amount of interruptible load these customers would offer to the Request For Proposals process would not be significantly higher than the amount of interruptible load currently contracted and administered by TransAlta, and

• the price at which these customers would offer interruptible load to a Request For Proposals process would likely be higher than the credits paid by TransAlta under existing contracts.

In summary, termination of Option 12 contracts today would not bring significant additional interruptible load to help alleviate the current supply/demand imbalance and, moreover, termination of Option 12 contracts today would translate into higher costs as current interruptible loads would likely be offered at higher prices. Therefore, the Board is of the view that termination of Option 12 contracts today would not be in the public interest. Return of Option F Customers to Firm Rates

Having decided that termination of Option 12 contracts is not warranted, the issue of whether or not Option F customers should be allowed to take energy under a firm rate becomes moot until 31 August 2000, when these contracts expire. After 31 August 2000, customers that were under the expired Option F contracts should be treated like any other new customers and, therefore, be eligible to take power under any rate. However, if this matter is still an issue at the time of the 1999/2000 GRA Phase 2, the Board is prepared to hear representations at that time. Should Option F Contracts Remain With TransAlta as Applied For?

Intervenors argued that TransAlta’s use of a pool-price trigger resulted in many calls for interruption that were not made because there was an actual shortfall of generation, but rather because the pool price rose to the trigger level. In response TransAlta testified that it uses a pool-price trigger because it lacks visibility to identify an actual shortfall situation and that the pool price is the only indicator of the system’s hourly supply/demand situation. The Board is of the view that if it approves Option F as proposed, TransAlta’s use of a pool-price trigger would result in Option 12 customers being called to curtail their load on occasions when there is no generation/supply shortfall, especially when applied closer to the minimum price trigger of $40/MWh. However, the Board notes that Option F proposed by TransAlta indicates that “In exchange for credits, TransAlta will continue to direct these customers to remove their Option F load from the system when there is a shortage of generation.” Therefore, approval of TransAlta’s proposed Option F may result in numerous load curtailments when there is no generation/supply shortfall and this would be contrary to the spirit of the contracts. Decision U99035 Page 148 10 August 1999


Transferring Administration of Option F Contracts to Other Entity

This issue was raised by the ACD due to the fact that TransAlta had significantly increased the number of calls to curtail Option 12 loads in recent years. The increase in the number of calls to curtail loads is the result of two factors:

• TransAlta’s use of a pool-price trigger, as a means to identify a shortfall of generation situation, to call down interruptible loads, and

• Demand has increased without a corresponding increase in new generating sources. The Board notes that all parties, including TransAlta, concurred that the System Controller is the entity who knows the supply/demand situation hour by hour in Alberta. Therefore, the Board agrees that the best way to direct Option F customers to curtail their load only when there is a shortage of generation, would be if the direction comes from the System Controller. Intervenors submitted that the administration of Option 12 contracts should be transferred to the System Controller. However, as stated above, absent agreement from all the parties, the Board could not direct the assignment of contractual rights and responsibilities to a third party who was not a party to the agreement. Therefore, an agreement between TransAlta, its Option F customers, and the System Controller would be necessary to allow transfer of administration to the latter. To this end TransAlta proposed (in Reply to Argument) that the Board establish a framework for a negotiated settlement aimed at finding a method where the System Controller makes the determination when Option F is to be curtailed. The ACD companies, however, rejected TransAlta’s negotiated settlement proposal. Therefore, in order to achieve a transfer of responsibilities for call downs to the System Controller, as this was acceptable to all parties and the Board, and at the same time maintain the Option F contracts within TransAlta, the Board directed TransAlta, in Decision U99026, to approach the System Controller to find a way whereby the latter would inform TransAlta when to call down Option F loads. The Board also directed TransAlta to report back to the Board, within one month from the issuance of Decision U99026, indicating the result of its conversations with the System Controller. Subsequent to Board Decision U99026, TransAlta reported on 24 March 1999 that it had executed an agreement with the Power Pool, as requested by the Board, whereby the Pool will be solely responsible for determining when Option F load is to be curtailed. Should Option F Be Allowed to Buy-Through Their Interruption?

The Board is of the view that it would be imprudent to allow Option F customers to buy-through their interruption in light of the current supply–demand imbalance, which has resulted in erosion of reserve margins and the consequential curtailments of firm load customers during 1998. The AIS needs interruptible loads that can be relied upon when called and, as the buy-through Decision U99035 Page 149 10 August 1999


proposal defeats this objective, the Board will not approve it. Furthermore, the buy-through proposal was advanced by the ACD companies as a mechanism that would allow them to reduce the number of times they have to curtail load. However, the Board’s decision to direct TransAlta to enter into an arrangement whereby the System Controller informs TransAlta when to call down Option F loads should result in significantly fewer interruption calls to Option F customers. Should the Credits Be Increased and/or the Penalties Decreased?

The Board notes that the level of the interruption credits and non-compliance penalties were the matter of contracts between TransAlta and its Option F customers. The Intervenors did not present substantial evidence to persuade the Board that the value of the interruption credits should be increased by a factor of 10 or any other factor. Nor did the Intervenors convince the Board that the non-compliance penalties are too harsh. The Board expects that its decision respecting placing the call down with the System Controller should result in significantly fewer interruption calls to Option F customers and this should alleviate the concerns of the ACD companies that they were not getting enough value for their interruption. Furthermore, Option F customers would be called to curtail their load when called in response to a request from the system Controller and this convinces the Board that the imposition of current non-compliance penalties is warranted. (7) Option G C Planned Interruption Transition Credit

This transition alternative was available to customers with load on Option F (formerly Option 12) as of 30 June 1996 and who elected this option prior to 31 December 1996. Customers are subject to the hourly pool price for the energy portion of their bill and receive a percentage of the Option F credit when they self interrupt. This percentage declines from year to year. The Generation Access Charge (GAC) is the element of the rate designed to make this option, on a total class basis, revenue neutral to fixed price Rate 790. The GAC has been flowed through to individual customers on a per kW basis. If customers could manage their load such that they were purchasing energy at a below average pool price they would enjoy a net benefit from being on this option in comparison to the fixed price rate. Customers purchasing energy at above average pool prices would be worse off under this option. TransAlta noted on the rate schedule that, when this option expires at 31 August 2000, customers will be required to move their Option G load to any rate that flows through the pool price and not be eligible to move back to any rate which includes embedded energy pricing, such as Rate 6400. The issues raised with respect to this rate option were whether there should be a GAC and if its purpose was to make the option revenue neutral to firm rates, the flow through of TA charges to customers on this option, and whether customers on this rate option should have the right to revert to embedded energy rates upon expiry of their contracts.




TransAlta stated that this option developed through consultations with IPCAA and Option 12 customers. TransAlta submitted that this option is the equivalent to a New World Option 12. Customers would not be required to shed load but would have an economic incentive to do so by being exposed directly to the pool price and receive reduced Option F credits. TransAlta explained that the GAC on both Rate 780 and this option was designed to make revenues received from these tariffs revenue neutral to what would be received on Rate 790, on a forecast basis. However, as part of the 1998 Negotiated Settlement, the parties agreed to eliminate the GAC of $0.90/kW effective 1 July 1998. TransAlta, during the course of the hearing, proposed to reintroduce the GAC effective 1 January 1999, in order to meet the original spirit and intent of the GAC in keeping Rate 780 and Option G revenue neutral to Rate 790. TransAlta commented on IPPSA’s assertion that TransAlta unilaterally decided to eliminate the GAC, stating that the elimination of the GAC was part of the 1998 Negotiated Settlement. TransAlta also dismissed the Drazen formula proposed by IPCAA saying that it was not sufficiently developed and was unnecessary. TransAlta proposed to use its current GAC formula, re-implementing it 1 January 1999, calculating it quarterly, and offered to use a quarterly forecast, and a deferral account to capture differences between actual and forecast pool prices. TransAlta later proposed to liquidate any deferral account balance during the subsequent quarter. Subsequent to the hearing, by letter dated 22 January 1999, TransAlta submitted a filing for acknowledgement with the Board in which it proposed to re-implement the GAC effective 1 January 1999. The GAC would be calculated on a monthly basis instead of a quarterly basis as was proposed at the hearing. This filing also clearly demonstrated that the GAC could be either a negative or positive amount, depending upon the level of the pool price. As this filing was received after the hearing the Board notified the interested parties, giving them the opportunity to comment upon the proposed change. Finally, TransAlta dismissed the suggestion of IPCAA that Option G customers be allowed to take service under any rate for which they would otherwise qualify at the end of their current contracts. TransAlta stated that the restriction on returning to rates which included embedded energy pricing was an essential element of the agreements and was known by the customers. Position of the Intervenors

IPCAA

IPCAA noted that Rate 780 was originally designed to be a pool price flow through rate that would be revenue neutral with Rate 790. The GAC is the only hedge mechanism available to Option G customers and is therefore an essential element of the rate. IPCAA agreed with TransAlta that the GAC should be reinstated and went on to state that it would expect the GAC Decision U99035 Page 151 10 August 1999


to actually be negative to maintain revenue neutrality. However, IPCAA continued to be uncertain as to the details of the TransAlta proposed GAC. IPCAA supported the DCGI evidence which called for the GAC to be set by a formula, rather than being a single number as in the case of TransAlta. The DCGI stated that the purpose of the GAC is to offset the difference between embedded cost and average pool price. Being exposed to the volatility of the actual hourly pool price still gives the customer the incentive to self curtail. IPCAA did not comment directly on the TransAlta filing of 22 January 1999 with respect to the GAC. A group of Option G customers and IPCAA members, however, did support TransAlta’s proposal in a statement which accompanied TransAlta’s filing. They also continued to maintain their right to return to firm rates such as Rate 790 when their Option 21 contracts expired. IPCAA also addressed the issue of the increases in TA costs being passed through to Option G customers, claiming they are substantial and have been made without explanation. It suggested that, to hold Option G customers whole, either TA charges be held constant from when the GAC is set or that the changes in TA charges be included in the true-up of the GAC. IPCAA also maintained that when the current contracts expire customers should be able to switch back to any rate that they would otherwise be qualified for and not be restricted by their status as former Option G customers. IPCAA disputed TransAlta’s claim that it did not receive a hedge for this load, stating that it is inconsistent with TransAlta’s offer to let Option F (formerly Option 12) customers become Rate 790 customers. It is also inconsistent with the claim that Rate 780 was to be revenue neutral with 790 and with the fact that TransAlta has taken on new customers since 1996. With respect to not receiving a hedge for Option F load, IPCAA maintained that TransAlta effectively received an entitlement to energy at embedded cost for Option F load but no obligation to pay reservation payments, thus making 780/Option F load cheaper than regular 790 load. IPCAA responded to the following points from the FIRM Customers:

• the “FIRM Customers” do not speak for all or even most of the firm customers as IPCAA’s members are among the largest firm customers,

• that the “change” to Option G of most concern to the FIRM Customers, adjusting the GAC so that Rate 780/Option G continues to be revenue neutral with rate 790, is not really a change as this has been fundamental to Option G, and

• there is no evidence on the record to support the positions of the FIRM Customers. The only evidence adduced is that of IPCAA and TransAlta, and that supports the principle of revenue neutrality as the goal of the GAC.

In conclusion IPCAA stated that if the position of the FIRM Customers with respect to the GAC is adopted it would be only fair to allow Option G customers to revisit their decision to take service under this option. Decision U99035 Page 152 10 August 1999


FIRM Customers

The FIRM Customers did not support any of the changes proposed by TransAlta or IPCAA. They opposed:

• reinstatement of the GAC, • adjustments to the GAC so that customers in Rate 780/Oprion G are revenue neutral to

customers in Rates 790, 6300 or 6400, and • allowing customers in Rate 780/Option G to return to embedded rates.

The FIRM Customers claimed that none of the information filed with the interested parties in June 1996, when Option G was introduced, contained any reference to any adjustment to the GAC. Nor does the rate schedule for Option G indicate that the GAC would be adjusted periodically. The FIRM Customers recommended that the Board reconfirm the terms and conditions of the existing Option 21 rate, including the provision restricting customers in this rate from returning to fully hedged or embedded rates. The FIRM Customers submitted that to provide this load with anymore than a 19% hedge would be inappropriate, unreasonable, and unfair to all other existing customers. The 19% is equal to 1/6 of Class III load, which was deemed by the Board to attract generation capacity cost in the 1994 EEMA Decision. In response to IPPSA/SPPA’s suggestion that current Option G customers transfer to Rate 6800 (DAT), the FIRM Customers submitted that customers on Option G, which is a partially hedged rate, should not be eligible for the fully hedged Rate 6800. The FIRM Customers also commented on the suggestions presented by Enmax. The FIRM Customers stated that if these contracts are suspended and transferred to the System Controller they will be interrupted for the benefit of all AIS customers. The costs would be borne only by TransAlta’s firm customers however. The FIRM Customers stated that this process lacked symmetry and in order to protect firm customers TransAlta’s should be allowed to pass through the costs of contract suspension to all other discos and their customers. The FIRM Customers also disagreed with Enmax’s suggestion that Option G customers have been fully hedged loads since their inception. The FIRM Customers reiterated its contention from argument that the evidence indicated that this load was only 19% hedged. This being the amount deemed by the Board to attract generation costs. Finally, The FIRM Customers also took issue with Enmax’s suggestion that the releasing of Option F/G load was the same as a DISCO taking on new load and that the cost of this should be borne only by the DISCO in question. The FIRM Customers submitted that as all AIS customers benefited from Option F/G load then all customers should bear the cost of releasing this load. The FIRM Customers were also the only intervenor to respond to TransAlta’s filing of 22 January 1999 with respect to the GAC. They reiterated their opposition to the GAC formula as proposed by TransAlta and restated their argument that this rate be provided with no more than a 19% hedge.



IPPSA/SPPA

IPPSA/SPPA concurred with TransAlta’s proposal to re-implement the GAC and submitted that for rate stability and fairness reasons Option G/Rate 780 customers should retain their obligation/entitlement to the SC/RV, as rate 780/Option G were to be revenue neutral to Rate 790. IPPSA/SPPA was not exactly certain how the GAC would be calculated, however, and pointed out that for rate 780/Option G customers to remain equivalent to Rate 6300/6400 customers they would have to be entitled to the legislated hedges, as are all of TransAlta’s customers. IPPSA/SPPA also noted that when the GAC was replaced in the Option G tariff that it became virtually identical to a DAT. IPPSA/SPPA therefore recommended that Option G customers take service under Rate 6800 and receive the Option G credits for interruptibility. Option G should be modified to eliminate reference to generation and wires service charges, and reflect only the remaining interruptibility credits. IPPSA/SPPA took issue with the FIRM Customers’ position that option G customers should only receive a 19% hedge and submitted that there is ample evidence to demonstrate that the original GAC was developed such that Rate 780 and Rate 790 would be revenue neutral, effectively providing Option G customers with a significant hedge. IPPSA/SPPA also noted that Option F customers were offered the option of returning to firm service, an option which also provided for the full cost/value of a hedge. Enmax

Enmax recommended that Option G and F contracts be suspended provided that these customers bid in at least as much power to the request for proposal (RFP) process of either the TA or the Power Pool. Enmax also stated that all customers should pay for the incremental costs of the RFP process. Enmax also addressed TransAlta’s claim that it should be compensated for release of such load. Enmax stated that this is much like taking a new customer onto the system. No increase in hedge is granted to the DISCO and such increased costs must be spread throughout the DISCO, not distributed outside of the DISCO. The fact that these increased loads may not be covered is simply part of the additional risk that may be borne by DISCOs during the transition to customer choice. Enmax also stated that Option G customers are firm load customers that self interrupt and, when they originally entered into these contracts did so under the premise that it would not exceed the cost of firm load. Enmax therefore maintained that this load was fully hedged from its inception. Board Findings

With respect to the GAC the Board notes that Order E95123 specifically stated that Rate 780 was to be revenue neutral to Rate 790. Option G is identical to Rate 780 with the exception of the reduced Option F credits that Option G customers receive for self interrupting. Therefore, the



Board considers that Option G, like Rate 780, should be revenue neutral to Rate 790. The Board accepts that the GAC is the element in the rate used to achieve revenue neutrality. The Board notes the concern expressed by IPCAA regarding the flow through of TA charges to Option G customers. In Order U98193 dated 24 December 1998 the Board granted interim approval to an application by TransAlta which among other things addressed IPCAA’s concerns by fixing TA charges applicable to Option G customers at those prevailing on 1 January 1998. The Board finds that fixing TA charges at 1 January 1998 levels assists in keeping Option G revenue neutral to Rate 790 and therefore grants final approval to this item. The Board further notes that on an ongoing basis, Option G as proposed calls for the delivery charge contained in the option to be that as found in the applicable Rate 6200, 6300 or 6400. With respect to the exact formula to be used to calculate the GAC effective 1 January 1999, the Board notes that the formula submitted by TransAlta in their filing of 22 January 1999 achieves revenue neutrality with Rate 790 and has been supported by Option G customers. Therefore, the Board approves the GAC calculation contained in TransAlta’s filing of 22 January 1999. The final issue addressed respecting this rate is the condition in the rate schedule which prohibits customers from moving to any rate which includes embedded energy pricing (such as Rate 6400) upon expiry of their Option G contracts. Argument relating to this point centered around whether or not Option G customers should be allowed to move to a rate that is effectively hedged. The Board notes the argument of IPPSA/SPPA that, just as the GAC was designed to make Rate 780 revenue neutral to Rate 790, providing Rate 780 customers a significant hedge, the same revenue neutral feature of Option G effectively provides those customers with a similar degree of hedging. The Board also notes the Option G rate schedule, originally approved in Order U96053, which states that customers are not allowed to return to rates which include embedded energy pricing. In this particular context, the Board considers this to mean rates which offer fixed energy prices. The Board does not consider that this restriction is meant to apply to rates such as the actual pool price DAT which, while flowing through the pool price, also offers the value of a hedge. The Board also notes that with the arrival of full competition in 2001 more options should be available to all customers. The Board therefore approves Option G as filed. (8) Options F & G C Interruptible Credits

IPCAA raised the issue of the dollar amount of credits forecast by TransAlta to be paid to interruptible customers, and used in the Application to develop rates for firm customers. TransAlta forecast that credits totaling $19.1 million, on an annual basis, will be paid to customers on these options. This is based on the 1996 forecast.




IPCAA referenced the DCGI evidence which stated that actual credits paid to Option F & G customers amounted to only $8 million for 1998. The DCGI noted that in 1996 a number of Option F customers reverted to firm service, and therefore did not receive any credits, or reverted to Option G which has a reduced level of credits for self interrupting. IPCAA stated that this was not a Phase I issue because the level of credits did not affect total cost of service but rather the credits paid to interruptible customers and the rates charged to firm customers. IPCAA raised the question as to whether or not the over collections of 1997 and 1998 should be recognized in some fashion. IPCAA suggested that a relevant factor here was that the reduced credits paid by TransAlta resulted from the reduced level of curtailable load, which led directly to the brownouts of last summer and fall. IPCAA recommended that, for the purposes of this proceeding, the actual credits paid should be added to firm rates and that this should be made effective 1 January 1999. IPCAA further submitted that it was appropriate to review the 1997 and 1998 rate reduction riders and that TransAlta be ordered to refund the over collection of credits for those years. TransCanada noted and supported the DCGI evidence. The FIRM Customers also noted the over collection of credits indicated by the DCGI evidence. The FIRM Customers submitted that this was not a Phase I matter as it was revenue neutral. Regardless of the level of the credit/charge the revenue requirement remains unchanged. There is an impact to rates however. The proposed rates will collect excess revenues to the extent of $11 million. The FIRM Customers recommended that the cost of service allocation to rate classes be adjusted to reflect the lower level of interruptible charges/credits and the proposed rates be reduced to reflect the lower level of credits TransAlta will have to pay to interruptible customers. Position of TransAlta

TransAlta, stated that the 1997 and 1998 Negotiated Settlements were high level documents which looked at overall changes in costs and revenues, including the impacts of interruptible credits. The settlements have already taken into account all issues and it would be highly inappropriate and contrary to the spirit of the settlements to start identifying specific costs or revenues for adjustment. Board Findings

With respect to the credits paid in the 1997 and 1998 years, the Board notes that the parties had the opportunity to raise this issue during the course of the 1997 and 1998 Negotiated Settlements. The Board does not consider it appropriate for it to selectively open settlements that have already been agreed to by the parties. The Board also considers this to be a forecast cost issue that should more properly have been raised in the negotiated settlement process.



With respect to the 1999 year the Board notes that the appropriate level of interruptible credits and the allocation of this cost will be determined as part of the 1999/2000 GRAs currently before the Board. (9) Option H C Night Use Option

TransAlta proposed to close Option H, Night Use Option (formerly Option 16) and phase it out. Option H would be available to any customer taking service under Option 16 or Rate 770 as of 1 July 1998. In the interest of rate stability, TransAlta proposed to close the Night Use Option to new customers and begin its phase out to existing customers. Customers taking service under Option H would be billed on a demand based on the higher of 60% of their off-peak demand or 100% of their on-peak or shoulder demand. The Night Use Option would be available for a minimum of 12 consecutive months to services:

• that were on Option 16 or Rate 770 as of July 1, 1998, • on the Small General Service, General Service, Large General Service, Transmission

Service or Oil & Gas Service Rate, • with approved TOU metering, and • located where TransAlta has sufficient transmission and distribution capacity

available at night. A Night Use customer’s bill would be calculated on the Small General Service, General Service, Large General Service, Transmission Service and Oil & Gas Service Rate, with the modification that the Metered Demand would be the greater of:

• the registered demand in kilowatts or, if greater, 90% of the registered demand in kilovolt-amperes established between the hours of 8:00 a.m. and 9:00 p.m., or

• 60% of the registered demand in kilowatts or, if greater, 54% of the registered demand in kilovolt-amperes established between the hours of 9:00 p.m. and 8:00 a.m.

TransAlta proposed to withdraw Option H, Night Use Option for all customers on 31 December 2000. TransAlta indicated that The Night Use Option was introduced at a time when no incremental generation and transmission costs were incurred for additional off-peak demand. Under the Night Use Option customers received a price reduction at night through lower Time-of-Use prices for generation and transmission.




TransCanada

TransCanada stated that, by closing Option H to new customers, TransAlta has effectively created two rate classes for every rate class formerly entitled to Option H and without further justification, that would be discriminatory. TransCanada noted that, given the current supply demand shortages in Alberta, closure of Option H in the interests of rate stability would be unreasonable. TransCanada noted that TransAlta proposed to withdraw Option H for all customers on 31 December 2000. TransCanada noted that, while Option H would be available for a minimum of 12 consecutive months, the proposed rate does not require a long-term contract. Option H would unlikely be an option such as Option F, Planned Interruption Option, where TransAlta needed to give notice of termination. TransCanada stated that Option H offered a reasonably strong price signal for customers to move load off-peak, from a rate design perspective and that TransAlta’s DAT would be the eventual replacement to encourage customers to move load off-peak. TransCanada also stated that by closing Option H, TransAlta was proposing to remove the only other strong incentive that new customers might have to shift their load off-peak. Board Findings

The Board notes TransAlta’s statement that the Night Use Option was introduced at a time when there were no incremental generation and transmission costs for additional off-peak demand. To the extent that this is no longer the case, the Board considers that it would be appropriate to amend the rate. Instead, TransAlta has chosen to withdraw this Rate Option as TOU Rates are available. The Board considers that choosing to withdraw the Night Use Option is reasonable because of the availability of off-peak pricing through TOU rates. The Board does not agree with TransCanada that it is discriminatory to have Rate Option H only available to existing customers of Option 16 or Rate 770. As TransAlta is planning to withdraw the rate at the end of the year 2000, it would be inappropriate for new customers to make their economic decisions based on a rate that will not continue to be available. It is also fair to grandfather existing customers in order to provide ample notice of TransAlta’s intention to withdraw the Rate Option. However, the Board considers that any customer on Option 16 or Rate 770 before 1 August 1999 should be grandfathered as there may be customers who chose this rate option between 1 July 1998 and 1 August 1999. The Board sees no reason to treat these customers differently than the other existing Option 16 or Rate 770 customers. The Board therefore approves Option H as proposed with the adjustment that the first condition under the availability of the Option be changed to:

• that were on Option 16 or Rate 770 as of August 1, 1999.



(10) Option I C Reactive Power Option

TransAlta is not proposing any changes to Option I, Reactive Power Option, formerly Option 17, which would be available for a minimum of 12 consecutive months to services:

• on the Small General Service, Oil and Gas Service, General Service, Large General Service, Transmission Service, and Wholesale rates, and

• with approved electronic metering. The Reactive Power customer’s bill would be calculated on standard rates plus a Reactive Power Charge of $.90 per month per maximum registered kVAR in excess of kVAR at 90% power factor. For customers billing on the Reactive Power Option, the Metered Demand applicable in standard rates would be defined as the registered demand in kilowatts. Upon acceptance of the Reactive Power Option, customers would pay a one-time charge of $650 which would include electronic metering, if required. Board Findings

The Board notes that TransAlta has not proposed any changes to Option 17 except that it will now be referred to as Option I. There were no comments or objections raised from parties respecting Option I. The Board, therefore, confirms that Option I, Reactive Power Option, will continue in the same manner as the former Option 17. (11) Option J C Bill Reduction Credit

TransAlta proposed to change Option J (formerly Option 19), the Bill Reduction Credit rate to a minimum annual rate of eight per cent. The Bill Reduction Credit rate would be adjusted every January and July based on market trends and would be credited each month on the customer’s bill based on the additional contribution and the current credit rate. The Bill Reduction Credit would be available to customers on any rate who have a contract demand below 2,000 kW. The Bill Reduction Credit would not be available to those customers who have requested a refund of contribution, on the same service, within the previous twelve months. The Bill Reduction Credit would reduce the customer’s bill to the extent that the customer makes an optional additional customer contribution towards the investment cost of his service, subject to the maximum TransAlta investment on that rate. TransAlta stated that the additional customer contribution would be refundable to the customer upon request.



Board Findings

The Board approves TransAlta’s proposed change to the Bill Reduction Option (formerly Option 19). The Board notes that the Bill Reduction credit rate will be adjusted every January and July. (12) Option K C Municipal Adjustment Option

TransAlta proposed the introduction of Option K, Municipal Adjustment Option which, in conjunction with the Residential Rate and the residential investment policy, would allow municipal governments some flexibility in the provision of electric service to their residents. Residents in municipalities, which forego TransAlta’s maximum investment in new services, would receive a credit in lieu of the maximum investment. If municipalities take advantage of additional TransAlta investment, a surcharge would be applied to the customers’ bill. Option K would be available to residential customers in municipalities which pass a resolution to opt out of TransAlta’s standard investment policy. By such a resolution, the municipality may opt to accept more or less investment than would otherwise be made under TransAlta’s standard investment policy. TransAlta proposed that the financial impacts of the choice to opt for more or less than TransAlta’s standard investment would be calculated based on TransAlta’s standard utility costs and applied to the delivery charge for all affected services within the municipality in question. Board Findings

The Board notes that Option K is a new rate option available for municipalities that may choose to opt out of TransAlta’s standard investment policy. The Board considers that the inclusion of Option K provides some additional flexibility to municipalities. The Board considers that it is appropriate to approve Option K at the same time that it approves TransAlta’s other rates, after the refiling. (13) Option L C Seasonal Service Option

TransAlta proposed the introduction of Option L, Seasonal Service Option, which would evenly distribute the annual costs of delivery over the months that the service would be active. Option L would be available to customers who could define their normal operating season and would qualify for one of Rates 2100, 2200, 4100, 4200, 6100 or 6200. A seasonal service option customer’s bill would be calculated on the applicable standard rate with the following modifications:



• For a billing period in the On-Season:

The Delivery Service Charge for kW of Capacity of the standard rate is increased by multiplying the charge by the ratio of 12 months divided by the number of On-Season months.

• For a billing period in the Off-Season: The Delivery Service Charge for kW of Capacity is decreased to zero.

All other Generation and Delivery Service Charges under the standard rate would apply in each billing period. The On-Season would be selected by the customer and could be up to and including eight consecutive months. The customer could change the On-Season or change to a standard rate at the end of any 12-month interval from commencement of taking this option. The customer must notify TransAlta of such change one month in advance of the change.

Board Findings

The Board notes that TransAlta’s proposed Option L provides an option for seasonal customers who do not consume electricity at certain parts of the year. The Board considers that Option L provides flexibility to customers and approves the rate as proposed. (14) Generator Adjustment Rider

TransAlta proposed the introduction of this rider in accordance with section 49(5) of the EU Act and section 9 of the Deficiency Correction Regulation. The rider would be applied if the Distribution function experiences changes in costs of power purchased from the Power Pool of Alberta when the owners of regulated generating units temporarily suspend their obligation to pay the unit obligation value in respect of the owners’ interest in the unit. Position of the Intervenors

IPCAA

IPCAA suggested that the New World structure created opportunities for risk management and that TransAlta had proposed rates that shift additional risk onto customers. IPCAA noted that the rider would automatically flow through any changes resulting from a temporary suspension of Unit Obligation Amounts. This would effectively insulate TransAlta DISCO from any risks related to temporary suspensions and make it indifferent to the costs.



IPCAA maintained that this change was not contemplated in the 1996 Phase I. It would effectively shift risk to customers and would amount to an automatic increase in revenue requirements they would bear. IPCAA suggests that if TransAlta DISCO wishes to be in the position of managing the legislated hedges on behalf of its customers it should also have the obligation to minimize those costs through intervention in any Temporary Suspension application by GENCOs. IPCAA recommended that the application for the rider be denied. TransCanada

TransCanada suggested that TransAlta was looking ahead and taking care of their need to rapidly incorporate increases in costs into their rate structure. Position of TransAlta

TransAlta stated that the basis for TransCanada’s claim is unknown and undisclosed. TransAlta maintained that the purpose of the rider is to flow through the cost effects resulting from Board decisions to temporarily suspend the obligations of the owners of regulated generating units, and to do so in a timely fashion. TransAlta stated that IPCAA’s position was unreasonable and based upon an inaccurate understanding of the question of risk. No discussion from the Phase I proceedings or decision is cited to support the contention that TransAlta’s DISCO function was to bear the risk of increased costs due to the temporary suspension of GENCO obligations. TransAlta noted that the Phase I Decision made no mention of this question as it related to distribution function risk. TransAlta submitted that the proper time to test the validity of the temporary suspension and the costs thereof is in the context of the generator’s application to the Board for the suspension of its obligations. TransAlta further submitted that if the Board approved a temporary suspension order there was no purpose in a subsequent proceeding to determine if the customers are responsible for the costs. TransAlta stated that it only sought to minimize costs and avoid unnecessary duplication of regulatory effort. IPCAA’s criticisms should therefore be rejected. Board Findings

The Board is not convinced that there is a need for an automatic adjustment rider at this time. The Board notes that neither the Application nor the proposed Rate schedule for the Generator Adjustment Rider fully explains how the Rider would operate. The Board also recognizes that TransAlta would be able to apply for an adjustment to its rates in the event a plant should have its obligation temporarily suspended. The Board considers that issues related to an appropriate adjustment level and method would be more clear at that time.



Therefore, the Board will not approve an automatic generation adjustment rider for TransAlta at this time. (15) Additional Options Being Withdrawn

TransAlta proposed to withdraw the following rates: • Option S B Emergency Interruptible Option • Option 6 B Seasonal Small General Service Option • Option 8 B Seasonal Large General Service Option • Option 14 B Low Ratchet Option • Option 15 B Daily Interruptible Credit

Option S was originally used as Class 1 interruptible load for generating capacity planning. TransAlta noted that this is no longer a generation issue. TransAlta stated that, since the TA will now procure system support services in a competitive manner, customers who provide system support services will deal directly with the TA. Options 6 and 8 are proposed to be withdrawn because TransAlta’s unbundling of rates puts seasonal services on an equal footing with other services. TransAlta noted that some Option 6 and 8 customers may find the proposed Seasonal Service Billing Option L to be attractive. TransAlta does not have any customers taking service under either Option 14 or Option 15 and therefore was proposing to withdraw the rate options. Board Findings

The Board notes that no parties objected to the withdrawal of any of the Rate Options 5, 6, 8, 14 or 15. The Board considers that TransAlta’s reasons for withdrawing these rates are reasonable. The Board, therefore, approves the withdrawal of Options 5, 6, 8, 14 and 15. The Board notes however, that, as proposed by TransAlta, Option 5 B Emergency Interruptible Option will not be withdrawn until the TA begins procuring system support services on a competitive basis but no later than 31 December 2000.



5. TERMS AND CONDITIONS OF SERVICE

(a) Residential Investment in Sherwood Park and St. Albert

Currently, as approved on an interim basis by Decision U96077 dated 1 October 1996, TransAlta invests a maximum of $1,660 for new residential services in Sherwood Park and St. Albert. For other residential services in TransAlta’s service area, TransAlta proposed to increase the maximum level of investment from $760 to $820 per service. TransAlta requested final approval on the maximum investment for residential services. The MI objected to TransAlta’s investment policy and submitted that the maximum investment of $1,660 for new residential services should be available to all customers. Position of TransAlta

TransAlta stated that, although the residents of Sherwood Park and St. Albert pay standard residential rates, both the density of services and higher incidence of underground facilities indicated that operation and maintenance efficiencies existed which were not available in smaller communities. TransAlta described one efficiency as the occurrence of damage to underground was less than to overhead lines. The second efficiency resulted from the ratio of customers to lineman. For Sherwood Park and St. Albert the ratio is 2,340 customers per lineman while in other municipalities the ratio is 1,665 customers per lineman. TransAlta submitted that either the rate could be reduced or investment could be increased to recognize the less than average operating costs. TransAlta suggested that municipalities would sooner have a higher investment amount rather than a lower rate to cover the costs of installing underground subdivision. TransAlta acknowledged that Sherwood Park had accepted the higher investment level while St. Albert had not. Position of MI

The MI submitted that, even if operating efficiencies were to exist, the differential in the cost of serving these municipalities should be reflected in the cost of service analysis. The MI stated the differential did not justify an increased investment level for servicing in new residential subdivisions. The MI submitted that TransAlta had not adduced any evidence to indicate that the cost of constructing underground facilities in new subdivisions in Sherwood Park and St. Albert was any different than in other municipalities served by TransAlta. Nor had TransAlta provided evidence to suggest that it was more costly to operate and maintain services in other municipalities when compared to Sherwood Park and St. Albert.


5. TERMS AND CONDITIONS OF SERVICE TRANSALTA 1996—Phase II

The MI stated that implying underground services resulted in a reduction to operating capital and maintenance costs was irrelevant. The MI submitted the investment policy related only to TransAlta’s portion towards the total cost of installing facilities in new subdivisions. The MI asserted that TransAlta had not demonstrated that the operating savings attributable to a higher incidence of underground service offset the incremental investment per residential lot. In addition, the MI stated that TransAlta did not demonstrate that the net present value of operating savings equated to the incremental investment thereby indicating that other customers were not being discriminated against or that Sherwood Park and St. Albert were not receiving preferential treatment. The MI noted that TransAlta’s incremental investment in Sherwood Park and St. Albert was included in the rate base paid for by all customers. The MI declared that TransAlta’s investment policy was discriminatory absent any cost related differences. The MI stated that nearby municipalities had similar servicing standards where customers were also served on the same rates. The MI submitted there was no meaningful information to suggest any differences in operating and maintenance costs or the capital cost of installations in new residential subdivisions. The MI further stated that the discrimination impacted the customers by (1) requiring purchasers of lots within communities within TransAlta’s service area, other than Sherwood Park and St. Albert to contribute an additional $840. And (2) other customers subsidized the higher investment level in these two communities. The MI submitted that all communities should be treated equally and the Terms and Conditions of Electric Service (clause 1.4.1 Residential Services) should be amended to provide the same maximum company investment of $1,660 for each residential service in all new urban subdivisions. Board Findings

In Decision U96077, the Board noted that parties expressed concern with respect to TransAlta tracking the costs of the higher investment level for underground services, allocating those costs and supporting its position for efficiencies in operations and maintenance. The Board agrees with the MI that TransAlta has not adduced any evidence to indicate that the cost of constructing underground facilities in new subdivisions in Sherwood Park and St. Albert is any different than in other municipalities served by TransAlta. The Board also agrees with the MI that TransAlta has not provided evidence to suggest that it is more costly to operate and maintain services in the new subdivisions of other municipalities than in Sherwood Park and St. Albert. Therefore, the Board is not convinced that the evidence filed supports differences in the investment level for underground services in different communities. Therefore, whether in Sherwood Park and St. Albert or other communities, all new residential subdivisions in TransAlta’s service area should be treated equally.



Therefore, the Board directs TransAlta to contribute to a maximum investment level of $1,660 for each new residential underground service and $820 for each new standard overhead service in TransAlta’s service area. (b) Investment Levels & Contract Length and Termination Notice

Generally, utilities develop maximum investment and customer contribution policies to allow new customer loads to be served at standard rates paid by existing customers. Utilities require the new customer to make a contribution towards that investment, if above normal investments are necessary to connect and service a new load, thereby maintaining equity with existing customers. TransAlta proposed one investment policy applicable to all General Service customers regardless of size. TransAlta proposed a maximum investment for expected service lives of 15 years or greater to be $667 per kW for the first 300 kW of expected maximum demand plus $167 per kW thereafter. TransAlta further proposed to remove the fixed 12% operation and maintenance charge and to apply prepaid operation and maintenance to vary with the expected life of the service. TransAlta proposed that an operation and maintenance charge be applied to customers with expected demands greater than 3,000 kW. TransAlta proposed a level of $600 per kVA for farm services to be consistent with the investment in General Services based on a 90% load factor. TransAlta’s Application did not propose terms and conditions of service that would result from a complete unbundling of contract terms into generation, transmission and distribution. Intervenors representing the large customers recommended TransAlta be directed to unbundle the contract terms for large customer contracts. IPPSA/SPPA also proposed an alternative policy consisting of 3 blocks: $850 per kW for the first 75 kW of billing demand, $450 per kW for demand above 75 and below 1,000 kW and $125 for all demand above 1,000 kW. IPPSA/SPPA proposed those customers in the higher first block would be ineligible for the unused investment credit as discussed in Option B, Section 4(b)(2). IPPSA/SPPA

IPPSA/SPPA stated that maximum investment policies were designed to avoid “undue” impact on existing ratepayers. IPPSA/SPPA explained that the impact on the existing customer was an incremental cost issue because a new customer would provide incremental revenues associated with the tariff charges and incremental costs associated with the load. IPPSA/SPPA suggested the incremental costs would include additional capital costs for attaching the customer and enhancing the existing grid, that would not have been incurred in the absence of the new load, and incremental O&M expenses associated with serving the new load. IPPSA/SPPA submitted



that if the incremental revenues exceeded the incremental expenses, the existing ratepayers would be positively impacted and would benefit from the net incremental revenue. IPPSA/SPPA suggested the maximum investment amount could then be deduced by taking the present value of the net incremental revenue. IPPSA/SPPA asserted that TransAlta had neither outlined objectives for its investment policy nor refuted the objective that a maximum investment policy should avoid undue impact on existing ratepayers. IPPSA/SPPA described a means of evaluating whether an investment policy met the no undue impact on ratepayers by having the revenues provided by the new customer recover the incremental capital investment and O&M costs associated with that new customer. IPPSA/SPPA stated that if this objective could not be met, wire rates would rise over the long run. IPPSA/SPPA submitted that TransAlta provided no evidence or economic rationale to support the proposed changes to investment levels or proposed modifications to Option B or to justify limiting the applicability of Option B. IPPSA/SPPA submitted that TransAlta had not re-examined its overall investment policy in light of changes to the industry structure. IPPSA/SPPA recommended that TransAlta undertake a review of its method for developing maximum investment levels. IPPSA/SPPA emphasized that its proposal was not a “very simple approach” as characterized by TransAlta. Rather, IPPSA/SPPA suggested the proposal was based on a comprehensive analysis which reflected the unbundling of utility service and was oriented towards the objective of ensuring that utility wires investment would not burden existing customers with higher rates. IPPSA/SPPA recommended that its proposal should be adopted, because TransAlta had not examined its own investment policy. IPPSA/SPPA supported the position of IPCAA and TransCanada that TransAlta be directed to file unbundled contract templates, noting that customers, currently forced to sign contracts, had transitional issues extending past 2000. IPPSA/SPPA also noted that the current treatment of bundled contracts could also be a barrier for customers pursuing self-generation projects. FIRM Customers

The FIRM Customers submitted that IPPSA/SPPA’s recommended blocked investment levels were not supported by any rigorous analysis as suggested in IPPSA/SPPA’s own request to require TransAlta to undertake a review of its method for developing maximum investment levels. The FIRM Customers noted that the oil and gas sectors were growing faster relative to other classes and, as a result, higher levels in the blocked investment profile had the potential for inter class inequities and should not be approved pending a review in a future GRA.



The FIRM Customers stated that, even though TransAlta had upgraded its notice period provisions to conform closer with the TA’s provisions, there remained a discrepancy between TransAlta and the TA for loads between 2,000 and 3,000 kW. The FIRM Customers recommended that TransAlta’s notice period should be adjusted to conform with the existing TA’s provisions. TransCanada

TransCanada noted that TransAlta was not able to “mesh” its investment policy with that of the TA. TransCanada suggested that without alignment of the two investment policies, cross subsidies could occur between customers of the utilities. TransCanada indicated that the TA’s approved tariff contained a Transmission Facilities Investment Policy that no longer required a long term contract commitment if no investment was required. TransCanada also noted that the TA’s policy allowed a customer to reduce its reserve capacity by 3 MW or less with one year’s notice. TransCanada submitted TransAlta should be directed to work with the TA to align the investment policies. TransCanada submitted that TransAlta could deny or delay customer choice through the enforcement of contract terms that made sense in the Old World, but did not in the new. TransCanada pointed to the Drazen evidence, which stated that lengthy contract terms were inconsistent with further movement to competition and that contract terms for distribution service were not necessarily appropriate for generation or transmission. TransCanada noted that customers wishing to access the DAT, with a view to saving money through load shifting, could be disadvantaged because billings on the DAT could fall below contract minimum, thereby reducing or eliminating the incentive to switch. TransCanada pointed out that TransAlta’s replies about how DAT customers could respond to price and reduce billings below contract minimums were inconsistent. TransCanada submitted TransAlta had stated, at one point, consideration would be given to remove or reduce contract minimums, a practice already in place for Option 21 and Rate 780 customers. At another point, TransAlta apparently stated that the minimum monthly bill would be calculated as two-thirds of the total bill, with no adjustment for DAT customers. TransCanada inferred from the inconsistency that the bills would continue to be full service bills with portions for generation, transmission, and distribution. TransCanada suggested that customers would have difficulty meshing the new rates with their existing contracts. Should TransAlta and their customers not know how contracts should be unbundled, then customers may lodge appeals with the Board. TransCanada also pointed out that new customers or existing customers, with expanded load requirements over 75kW, would be required to sign contracts during 1999 and 2000 that would extend beyond 1 January 2001. TransCanada also noted that TransAlta had indicated no plans were underway to make any changes to the termination notice. TransCanada suggested that



TransAlta might argue that unbundling of contracts could be taken care of during the upcoming proceedings on Distribution Tariffs. TransCanada rejected such an idea because of timing considerations. TransCanada submitted that, in conjunction with TransAlta’s practice for Option 21 and Rate 780, TransAlta should be directed to remove or reduce contract minimums when such minimums would act to prevent customers from moving to new rates and options, such as the DAT. TransCanada also submitted that TransAlta should be directed to unbundle their contracts into generation, transmission, and distribution contracts and to file boilerplate unbundled contracts with the Board and interested parties. Alternatively, should the Board decide to accept TransAlta’s bundled contracts, TransCanada submitted that the contracts should be modified to include an option allowing customers to choose an unbundled contract for “no choice” delivery services at the time when customer choice was implemented. TransCanada noted that TransAlta’s investment policy applied whether or not the facilities were transmission or distribution related. TransCanada suggested TransAlta implied long term contracts were appropriate for distribution property. TransCanada submitted that TransAlta was using lack of unbundling as an excuse to maintain long term bundled contracts, and stated that no unbundling was inappropriate when moving towards a competitive marketplace. TransCanada claimed if TransAlta had unbundled its investment policy as it had its transmission and distribution costs, appropriate contract terms for each unbundled contract could be achieved. IPCAA

IPCAA stated that TransAlta proposed a single contract for all service components such that the larger the load, the longer the term of the contract. IPCAA suggested that this proposal ignored the functional separation into generation, transmission and distribution and delayed the implementation of retail competition by forcing customers to continue taking service from the DISCO. IPCAA recommended that contract terms should be separate for each functional part. IPCAA refuted TransAlta’s claim, that the distribution function was responsible for legislated hedges which had a long lead time, by suggesting there was no lead time for these hedges. IPCAA suggested legislated hedges would be replaced by Purchase Power Arrangements within two years. With respect to generation, IPCAA pointed out that there was no lead-time for legislated hedges, stating that in 2001 the legislated hedges were to be replaced with Power Purchase Arrangements. IPCAA also submitted that TransAlta had taken contradictory positions, arguing that customers with hedges should not be released from them while, at the same time, stating that it did not have sufficient hedges to cover all customers. IPCAA stated that the effect of a customer reducing its load on the DISCO’s billings from the TA depended on how the customer was served. If a customer was served from a dedicated substation, then the termination/reduction notice should be similar to that of the TA. If a



customer was served from a POD, also serving other customers, then a reduction in load might be offset by an increase in the load of other customers at that POD and termination terms could be less stringent than the TA’s terms. IPCAA submitted that the termination provisions, related to distribution costs, should be a function of the amount of distribution costs incurred. IPCAA suggested that for large customers, distribution facilities might be minimal, perhaps just a meter, which could be recovered by contract provisions rather than by a specified contract term. Position of TransAlta

TransAlta stated the goals of its investment policy were intended to provide a reasonable level of investment for each customer, but not to burden all customers with the high cost of long or expensive connections which served only one customer. TransAlta set the investment level so that 80% of its customers would receive service without making a construction contribution. TransAlta reasoned that as inflation impacted both the connection costs and the rates, the maximum investment was revisited periodically to provide a similar level of facilities to new customers. TransAlta recognized that while increasing its maximum investment would increase rates, TransAlta concluded that it was also important to be as equitable as possible in the treatment of old customers and new customers, since both were paying the same rate. TransAlta proposed three objectives for its investment policy: i.) to increase the investment level for smaller customers; ii) to remove the discontinuity in investment levels at 3,000 kW; and iii) to maintain the existing unused investment levels for new customers over 3,000 kW. TransAlta suggested IPPSA/SPPA’s very simple approach to evaluating maximum investment levels combined the incremental costs associated with the load, which were the capital costs for attaching the customer and any incremental capital costs for enhancing the existing grid, and resulted in IPPSA/SPPA’s Theoretical Maximum Investment Levels. TransAlta suggested its maximum investment levels were generally lower than those proposed by IPPSA/SPPA because TransAlta did not consider any incremental capital costs for enhancing the existing grid when calculating the customer contribution. TransAlta also stated the maximum investment level applied to transmission customers. And, in so doing, TransAlta considered any incremental investment associated with the load, including that made by or on behalf of the TA, as being a TransAlta investment and recognized that investment when calculating the customer contribution. TransAlta suggested that treating a TA investment as a TransAlta investment was appropriate because the TA required a contractual commitment from TransAlta commensurate with the investment. TransAlta maintained that it must either make this long term contractual commitment or a commitment to pay a contribution according to Sections 6.3 and 6.5 of EAL’s Terms and



Conditions approved in Decision U98085. TransAlta submitted that appropriate long-term contracts were required with large customers to match TransAlta’s obligations to the TA. TransAlta noted that the Drazen evidence challenged the proposed length of contracts and termination notice. TransAlta submitted that the initial length of contracts and notice periods were appropriate since TransAlta could invest up to $300,000 for a 600 kW load. TransAlta stated that, for large customers requiring a minimal investment in distribution facilities, the investment policy applied regardless of whether the facilities were distribution or transmission-related. TransAlta also noted Mr. Drazen suggested that TransAlta should not require long term contracts for large customers as little investment was needed in distribution property. TransAlta submitted the investment policy applied whether the facilities were transmission or distribution related. TransAlta pointed out that to serve customers who required transmission facilities, TransAlta must either make a long term contractual commitment to the TA or pay a contribution. TransAlta commented on TransCanada’s criticisms, pointing out that portions of existing contracts could be overridden by customer choice legislation and that unbundling of contracts should be done subsequent to the unbundling of rates. TransAlta confirmed that it would not enforce those portions of existing contracts that were superseded by customer choice legislation. Board Findings

The Board agrees with TransCanada that without alignment of TransAlta’s and the TA’s investment policies, cross subsidies could occur between customers of the utilities. The Board also considers that TransAlta’s charges should not include any premium over the costs it will incur from the TA. The Board notes that the TA’s approved tariff contains a Transmission Facilities Investment Policy which does not require a long term contract commitment if no investment is required by the TA. Furthermore, the TA’s policy allows a customer to reduce its reserve capacity by 3 MW or less with one year’s notice. The Board considers that such terms should be available to TransAlta’s customers. Therefore, the Board directs that, for customers served at a single point of delivery at or above 25 kV, TransAlta’s contract for TA Billings should result in a pass through of all of the terms in TransAlta’s contract with the TA. While the Board recognizes that the current treatment of bundled contracts could be a barrier for customers pursuing self-generation projects, the Board is not convinced by the evidence adduced at this proceeding that it should allow customers to avoid their contractual obligations. However, in the interest of shortening the transition period after 2001, the Board considers that new or renewing TransAlta customers taking service before 2001 should not be tied to TransAlta for any longer than the minimum possible period for any cost source which will be competitive after 2001. Further, the Board considers that investment policy must reflect the separation of the integrated utility’s costs by function in the restructured industry. Therefore, TransAlta is directed to unbundle its investment policy and offer separate contracts for all of its new or renewing



customers for Energy Supply, TA Billings and DISCO Services each with an appropriate minimum term. TransAlta should provide examples of its unbundled contracts with its refiling. When comparing the two proposed investment level policies, the Board notes that TransAlta’s proposed investment would be more than IPPSA/SPPA’s proposal when demand is less than 138 kW or greater than 424 kW and TransAlta’s investment would be less when demand ranged between 138 to 424 kW as shown in Appendix 6. The Board notes the comments by the FIRM Customers and agrees that neither proposal is supported by any rigorous analysis. The Board therefore, directs TransAlta to review its investment policy and provide at the PDT proceeding the results of its review including the necessary evidence to support the determined investment levels including the breakdown of the portion of the investment which is for distribution system fixed costs and transmission system costs. For purposes of this decision, the Board accepts TransAlta’s proposal for calculating the maximum investment level. The Board has stated its finding with respect to Option B in Section 4(b) (2).



6. OTHER

(a) Interest on Adjustments

When a utility has interim rates in place it will normally collect revenues either surplus to, or deficient from, the revenue requirement which the Board ultimately approves. In the past the Board has not allowed interest on such a deficiency or surplus. Instead the Board has approved a rate adjustment intended only to refund the forecast surplus or to collect the forecast deficiency. This practice has been questioned in some recent proceedings. The Board therefore initiated a generic proceeding to deal with the question of whether or not it is appropriate for the Board to change its policy on the awarding of interest on rate adjustments for both electric and gas utilities. The Board stated in a letter dated 25 August 1998 that it would

…hold a proceeding in writing to deal with the matter of the payment of interest on adjustments to rates and other payments where necessary approval, and subsequent disposition, has been delayed in the normal course of proceedings. This matter is to be addressed in a more specific context in the Phase II portions of the 1996 Electric Tariff Applications and has also been raised in other proceedings.

Near the end of the Phase I portion of this application, in October 1997, IPCAA raised the issue of whether interest should be paid to customers on the refunds resulting from Decision U97065 (the 1996 Phase I decision). The Board responded to IPCAA by stating that the Board has the jurisdiction to deal with the question of interest on adjustments in the Phase II portion of the proceedings. The Board later clarified that the issue was to be addressed in the Phase II portion of the proceedings. Position of the Intervenors

Enmax

Enmax submitted that, since the Board stated in the Phase I portion of these proceedings that interest would be better dealt with in the Phase II portion of the hearing, it was appropriate for the matter to be addressed at this time irrespective of the generic proceeding dealing with the interest issue. Enmax recommended that customers should be refunded interest on the entire amount over collected as a result of the implementation of interim and final rates for 1996. Enmax stated that, as nearly three years have elapsed since TransAlta began over-collecting from customers, interest should be paid to customers. Enmax noted that the interest payments are not intended to be punitive but to reflect the time value of money.


Enmax submitted that the Board can vary its past practice of not awarding interest on adjustments and that it should do so to fit the circumstances of the day. Enmax stated that customers have not previously requested interest on refunds so the Board did not award interest

6. OTHER TRANSALTA 1996—Phase II

absent such a request. Enmax noted that in the specific case where the Board denied an interest award, in the case of TransAlta’s 1995 rate review, the Board did not refer to its general policy of not awarding interest. Enmax noted that, in TransAlta’s example of instances where refunds were ordered without the payment of interest, intervenors did not make any requests for the payment of interest. Enmax also noted that TransAlta did not point to any disadvantage or unfairness that it would suffer as a result of being required to pay interest on the 1996 refund. Enmax also suggested that the request for interest in the 1995 rate case should have put TransAlta on notice that customers would seek interest on refunds, particularly when there are large amounts of money at stake or there is a long time lag before the refund is received. IPCAA

IPCAA also submitted that TransAlta should pay interest on any amounts that it has been ordered to refund to customers. IPCAA stated that the EU Act does not prevent the payment of interest. IPCAA submitted that the payment of interest on rate adjustments arises from a principle of fairness. IPCAA submitted that rates that do not account for the time value of money cannot be just and reasonable. IPCAA noted that the concept of carrying charges is recognized by virtually every other rate regulating board and commission in Canada. These carrying charges whether or not they are calculated as interest, are applied to monies owed to or by the regulated entity in order to protect against the impacts of regulatory lag and other delays. This ensures that a party, either the utility or customer, is not unduly burdened if it does not receive timely payment of an amount that it is owed. IPCAA stated that amounts collected in excess of the approved revenue requirement are provided by customers at no cost. The utility is then able to finance a portion of its operations with these excess earnings even though the utility’s approved revenue requirement assumed a financing cost. IPCAA submitted that this enables a utility to earn in excess of the approved return on their investment. IPCAA submitted that any interest awarded in this proceeding must stipulate that the interest obligation be paid by the shareholders of TransAlta and not be recoverable from customers through rates as any other approach would defeat the purpose. IPCAA noted that, in Decision U96001, the Board directed NOVA Gas Transmission Ltd. (NGTL) to refund to customers the difference between the tolls resulting from the final determination of the utility’s revenue requirement and the tolls collected under interim rates together with carrying charges at the approved rate of return for rate base. IPCAA recommended that the Board adopt a similar approach in this proceeding. IPCAA submitted that TransAlta should pay interest on any amounts that it has been ordered to refund to customers and that interest should be payable at a rate equal to the composite rate of return on rate base of TransAlta on all outstanding amounts until the refunds have been completed.



IPCAA disagreed with TransAlta’s position that allowing the payment of interest in this proceeding would amount to applying a new practice retroactively. IPCAA noted that TransAlta was aware that the matter of interest would be dealt with in the Phase II portion of the proceeding. Also, IPCAA stated that TransAlta’s list of past rate adjustments that did not involve interest did not provide evidence of a long-standing policy of interest not being awarded but that parties have not requested interest. IPCAA also submitted that it was not sufficient that, over time, the instances of interest paid and collected may balance out. IPCAA stated that rates that do not account for the time value of money could not be considered to be just and reasonable and that it is necessary for the Board to consider in every case whether the payment of interest is appropriate. IPCAA further disagreed with TransAlta that there was insufficient evidence on the record to warrant a change in the Board’s practice and questioned what further information was required. In response to the FIRM Customers recommendation that Rate 720 customers should not receive any interest payment, IPCAA suggested that any such exclusion would be arbitrary and unjustified and should not be endorsed. FIRM Customers

The FIRM Customers noted that TransAlta’s over-recovery for 1996 was $56.3 million and that the midpoint of the over-recovery period was 1 July 1996 and the midpoint of the refund period was 1 July 1998. On this basis, the FIRM Customers recommended an interest recovery on the full refund amount for a two-year period. The FIRM Customers also recommended that interest should be compounded over the period rather than calculated as a lump sum. The FIRM Customers submitted that the Board should use an appropriate rate of interest, having regard to the generic interest proceeding. The FIRM Customers stated that the amount of interest should reflect the time value of money and provide compensation to customers, which is fair to both the customers and TransAlta. The FIRM Customers further recommended that the interest be included in a refund rider and reimbursed to customers on an across-the-board basis applicable to current rates, except for Rate 720 (Temporary Energy). The FIRM Customers recommended that Rate 720 be excluded from the payment of interest because they considered that Rate 720 should not be eligible for a refund as it is a market based rate and customers accept the rate offered at the time that the purchase is made. The FIRM Customers noted that there have been significant over-recoveries by TransAlta in the period from 1989 to 1997. The FIRM Customers suggested that the magnitude of the over-recoveries is dictating the necessity for a change in the Board’s policy regarding recovery of interest. The FIRM Customers disagreed with TransAlta’s position that it was unfair to grant an interest award in the middle of its rate case. The FIRM Customers noted that TransAlta did not forecast the over-recovery and the amount of the over-recovery was available as an offset to TransAlta’s cost of service. Therefore the over-recovery provided an immediate and real benefit



to shareholders through reduced costs. The FIRM Customers submitted that the question was not whether adequate notice was given, but rather whether the utility benefited at the cost of its customers. IPPSA/SPPA

IPPSA/SPPA fully supported the position of IPCAA on this issue. IPPSA/SPPA noted TransAlta’s statement that in 12 rate cases involving rate adjustments, six involved collections and six involved refunds. However, IPPSA/SPPA stated that, in the total dollar value of these cases, the amount of refunds to customers were nearly $200 million higher than collections. IPPSA/SPPA speculated that in the future, with only transmission and distribution related assets being regulated, it is likely that utility wires related rate bases will continue to decline in real terms because Alberta has a relatively mature electrical system. IPPSA/SPPA therefore speculated that it is unlikely that large over collections will occur. IPPSA/SPPA submitted that if TransAlta will have to pay interest on refunds, TransAlta will be revenue neutral to inflating their filings and delaying regulatory processes. IPPSA/SPPA suggested that the amount of the 1996 over-collection of funds from customers and the time lapse before TransAlta fully refunded the over-collections was unprecedented. IPPSA/SPPA submitted that, at the outset of the 1996 Phase I proceeding, TransAlta would not have known that its applied for revenue requirement would be reduced by approximately $56 million and that it would have the use of this money for up to three years. Therefore, this would increase TransAlta’s actual rate of return. IPPSA/SPPA recommended that TransAlta refund to customers the interest on over-collected funds from the 1996 Phase I decision. IPPSA/SPPA recommended that the rate of interest be set at TransAlta’s 1996 approved composite rate of return on rate base of 9.2% and that TransAlta shareholders and not TransAlta customers incur the interest expense. Position of TransAlta

TransAlta objected to the requests for interest and submitted that a departure from the Board’s long-standing approach to interest is unwarranted and cannot be made at the end of an electric utility general tariff proceeding without offending the principles of fairness and justice. TransAlta noted that the Board has a well established and long-standing practice with respect to interest for electric utilities that the use of interim rates be encouraged and refunds or recovery of deficiencies be done without adding interest to the amounts refunded or recovered. TransAlta noted 12 previous decisions of the Board involving refunds or recovery of deficiencies that dated back to the 1973/1974 test years. Interest was not awarded in any of these cases. TransAlta noted that the historical practice that developed was to bring interim applications to address concerns regarding the recovery of refund amounts and collection of deficiencies. TransAlta noted that the practice of allowing interim rates has proven an effective means of preventing the build-up of liabilities on the part of both utilities and customers and minimizes



intergenerational inequities that arise due to delay. TransAlta suggested that it was inappropriate to use the current regulatory lag as grounds to reverse the Board’s policy as it is temporary and will begin to ease as the industry moves beyond the initial phase of deregulation. TransAlta also noted that after 31 December 2000, only the wires services will be regulated, likely with longer test periods, and the probability of such refunds or collections will be significantly reduced. TransAlta noted that it did not seek interest on its long overdue deficiency when it was unable to recover a significant 1985 deficiency until well into 1986. TransAlta submitted that the experience has not been one-sided. TransAlta has been able to collect prior revenue deficiencies as often as it has been directed to make prior-period refunds. TransAlta submitted that there have been winners and losers but because the policy has remained consistent through the years and interim refundable rates have been encouraged, fairness has been achieved. TransAlta also submitted that so long-standing a practice should not be reversed in the middle of a utility’s rate case. TransAlta, as the applicant, is entitled to know, from the outset, the practices and procedures which will be applied by the Board in respect of its entire application. TransAlta submitted that, fundamental change to those practices and procedures cannot be made without offending the principles of fairness and natural justice. TransAlta argued that such a change would deny all parties the important opportunity to prepare their cases and make significant strategic decisions in reliance upon the Board’s past practices. TransAlta agreed that the Board can change its practice with respect to interest but such a departure can not be fairly made midstream and without adequate notice to the parties involved. TransAlta’s expectation was that the historic practice on interest would be maintained in the context of this application. TransAlta submitted that the appropriate forum to decide whether or not a fundamental shift in approach is appropriate is in the type of generic proceeding that the Board has initiated. TransAlta suggested that the convening of such a proceeding acknowledges the necessity of proper notice and that such changes are fairly made only on a go-forward basis. TransAlta noted the Board’s findings on the same issue in Order U98124 respecting IPCAA’s review of TransAlta’s 1995 rates. The Board concluded that there was insufficient evidence to warrant a change in the policy of not awarding interest. TransAlta submitted that the issue of interest was not discussed in any way in Phase I and was barely discussed in Phase II. Therefore, TransAlta submitted that there is again insufficient evidence to warrant a change in the Board’s practice. TransAlta disagreed with IPCAA’s suggestion that the award of interest in a NGTL application was relevant for an electric utility as the Board’s rationale for awarding interest in Decision U96001 does not apply in the electric utility context. TransAlta noted the prominent use of deferral accounts in the Board’s early regulation of NGTL and its current regulation of NGTL on a cost of service basis as examples of the significant differences between NGTL and the electric utilities. TransAlta submitted that it was these differences between NGTL and TransAlta that the



Board acknowledged in Order U98124 when it stated that it was not convinced that the principles from Decision U96001 were applicable to electric utilities. Lastly, TransAlta submitted that, should the Board choose to award the payment of interest, it would be inappropriate to award interest at the composite rate of return on rate base of the TransAlta DISCO. Instead, such interest should be calculated on the basis of simple interest over a short-term period. Board Findings

The Board is in the process of considering a policy on whether interest should be paid on rate adjustments and in what circumstances it would apply. Absent the Board’s finalization of its policy this panel will make a determination with respect to the payment of interest as it pertains to this application. The Board notes TransAlta’s concern that, should the Board choose to change its policy on the awarding of interest, it should not do so in the midst of an application. The Board considers however that IPCAA’s frequent requests for a change to the Board’s policy provided sufficient notice to parties in these proceedings that the Board’s policy could be reviewed. The Board notes that TransAlta implemented an across-the-board refund of its over-collections shortly after the 1996 Phase I decision was issued. The Board does not consider that the long delay in implementing rate refunds from the date of the application was a result of improper actions on the part of TransAlta. However, the Board notes that, in implementing final rates in this proceeding, the time delay has been longer than normal and the amount of the refunds are significant. Given these factors, the Board considers that, absent an award of interest, TransAlta shareholders have unfairly gained at the expense of ratepayers. The Board finds that the circumstances in this case warrant the payment of interest on refunded amounts. Having decided to award interest, the Board notes that there is no clear cut manner to determine the level or the manner in which the interest should be calculated. The Board will use some simplifying assumptions in this case to recognize that parties were not aware when the Phase I application was filed that interest would be awarded and that TransAlta began refunding the over-collections in a short time frame after receipt of the Phase I Decision (Phase I Decision U97065 issued 31 October 1997 and refunds began 1 January 1998). As noted in Board Order U97156, TransAlta’s revenue surplus was $55.56 million in 1996 and $56.35 million in 1997 as a result of the 1996 Phase I Decision. These amounts were refunded over the period 1 January 1998 until 31 December 1998. In the interests of providing a calculation of interest that is not overly complex, interest on the $55.56 million refund relating to the revenue surplus in 1996 will be calculated from 1 July 1996 to 30 June 1998. Interest on the $56.35 million refund relating to the over-collection in 1997 will be calculated from 1 July 1997 to 30 June 1998. The rate of interest to be used will be the Bank of Canada’s Bank Rate plus



1½%. The yearly average Bank of Canada Rate for 1996 is to be used to calculate the 1996 portion of interest (1 July 1996 to 31 December 1996), the yearly average Bank of Canada rate for 1997 is to be used for 1997 and the yearly average Bank of Canada rate for 1998 is to be used to calculate the 1998 portion of interest (1 January 1998 to 30 June 1998). The interest calculation will use a simple yearly rate and not a compounded interest rate. The interest will be refunded to customers on an across-the-board basis as the refunds were paid in 1998 excluding any market based rates. These interest payments shall be considered as a shareholder expense and can not be recovered from customers. The Board directs TransAlta to provide, in its refiling, a calculation of its interest refund and a proposed rider to refund the interest to customers.



7. SUMMARY OF BOARD DIRECTIONS

This section is a summary of Board directions and has been prepared for the convenience of all parties. The directions in the main body of the Decision shall prevail over this summary if there are any differences. 1. The Board therefore directs TransAlta to use actual 1998 pool prices for the purpose of

determining the cost of pool purchases used in the refiling. The actual 1998 pool price record should be utilized in the calculation of pool purchases, unit obligation values (UOV), TOU rates and annual average energy costs. (See also Section 3(b)) [Section 2(a)(1)] p.11

2. However, since in Section 2(c)(3), the Board finds that 25 kV costs should now be in

transmission, the Board directs TransAlta to also pass through the actual TA Billings to every customer served at 25 kV or higher who is the only customer at a point of delivery. [Section 2(c)(1)] p.31

3. Therefore, the Board directs TransAlta to investigate combining the NCP demand for

farm and irrigation service classes for the purpose of allocating TA Billings and provide the study at the preliminary distribution tariff proceeding. [Section 2(c)(1)] p.31

4. The Board agrees with IPPSA/SPPA that more detail may be necessary to demonstrate

that the allocations properly reflect the cost causation. Therefore, the Board directs TransAlta to provide information relied upon and relevant to determining the allocation of the town property to the customer rate classes at the time of its next Phase II GRA. [Section 2(d)(1)] p.37

5. The Board is not convinced that a minimum system method from 1990 is necessarily out

of date or inappropriate for determining cost causative factors. However, the Board directs TransAlta to update the study on the minimum system method as part of the information supplied to substantiate the allocation of town property. [Section 2(d)(1)] p.37

6. The Board directs TransAlta to record future customer contributions by the function for

which the contribution is received as well as by rate class. [Section 2(d)(2)] p.38 7. Therefore, the Board directs TransAlta to set its DISCO’s overall revenue-to-cost ratios to

100% for each cost source. [Section 3(a)] p.50

7. SUMMARY OF BOARD DIRECTIONS TRANSALTA 1996—Phase II 8. To ensure some degree of rate stability in moving to accurate cost signals, the Board

directs that in the refiling, the DISCO keep the overall increase in revenue arising 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 rate should be moved to exactly 100%, with the DISCO Services component (which is a residual) adjusted to ensure the overall increase in revenue is less than 10% for every rate class. [Section 3(a)] p.51

9. In summary the Board directs TransAlta to design rates so that:

• the DISCO’s total costs related to Energy Supply, TA Billings and DISCO Services are unbundled, with the revenue-to-cost ratio for each set at 100%,


• the overall increase in revenue over that collected from existing rates is kept at less than 10% for every class, by adjusting as required the “residual” DISCO Services amount to be recovered from customer classes. (The Board notes that individual customers may see more than a 10% increase if their usage characteristics warrant.) [Section 3(a)] p.52

• • • 10. The Board directs that TransAlta apply the actual 1998 hourly pool price record to

TransAlta’s actual 1998 class load data in its refiling. [Section 3(b)] p.53 11. The Board directs TransAlta to apply its actual metered class hourly load to the actual

1998 hourly pool price record to determine a more appropriate annual average cost of energy for each fixed rate class. [Section 3(b)] p.53

12. Similarly, the Board directs TransAlta to use the average actual pool price in each TOU

period in 1998 as the cost of energy components in the TOU rates. [Section 3(b)] p.53 13. The Board also directs TransAlta to use the fixed amount “H” charge calculated using the

1998 pool price record and total 1998 TransAlta DISCO annual energy usage. [Section 3(b)] p.53


7. SUMMARY OF BOARD DIRECTIONS TRANSALTA 1996—Phase II 14. The Board directs TransAlta to use the TA’s interim 1999 rates (as approved in Order

U99018 dated 11 February 1999) and TransAlta DISCO’s actual 1998 TA invoiced kWh and kW to determine updated TA Billings. The allocation to rate classes and transmission served customer classes should use actual 1998 hourly class load and NCP data to determine the kWh and kW charges. TransAlta’s per kWh and kW charges to recover TA Billings will then reflect the 1999 TA rates which are adjusted for the effect of reallocating the 25 kV plant to transmission (See Section 3(c)). [Section 3(b)] p.53

15. The Board also directs TransAlta to indicate the separate charges for the TA Billings and

DISCO Services components on each rate schedule. [Section 3(b)] p.53 16. The Board directs TransAlta to deduct the resulting total updated 1998 forecast costs of

Energy Supply and updated TA Billings from TransAlta DISCO’s 1998 negotiated revenue requirement (as approved by the Board in Decision U98093) and use the resulting 1998 residual as the cost of TransAlta’s DISCO Services in the refiling. [Section 3(b)] p.53

17. The Board also directs TransAlta to prorate the 1996 distribution cost allocations (as

adjusted for the removal of the 25 kV costs from distribution) in the Application to the 1998 residual in the refiling to determine the levels for the DISCO Services components in the refiled rates. [Section 3(b)] p.54

18. Further, the Board directs TransAlta to confine the entire effect of the across-the-board

rider arising out of the 1998 settlement agreement to the DISCO Services components of TransAlta’s rates. For those customers served at the transmission level the effect of the across-the-board rider should be confined to the TA Billings components. [Section 3(b)] p.54

19. The Board directs TransAlta to refile its COSS and rates on 1 September 1999. To

confirm compliance to the Board’s directions, the Board directs TransAlta to supply tables setting out revenue-to-cost ratios for each rate by cost source (Energy Supply, TA Billings and DISCO Services) and to confirm that overall DISCO revenue-to-cost ratios by cost source are at 100%. [Section 3(b)] p.54

20. In light of the load diversity that exists at the distribution level the Board considers a

demand ratchet of 85% appropriate for the TA Billings component of the rate for customers taking service at the distribution level. For such customers an 85% demand ratchet would also seem more appropriate for the DISCO Services components of the rate, since those components charge for marketing, metering and other DISCO Services not related to the size and cost of the distribution facilities. The Board directs TransAlta to make the necessary changes to its COSS and rate schedules. [Section 3(c)] p.57

21. Therefore, the Board directs TransAlta to maintain its existing policies with respect to Decision U99035 Page 182 10 August 1999

7. SUMMARY OF BOARD DIRECTIONS TRANSALTA 1996—Phase II

these matters for customers taking service at the distribution level. However, for customers taking service at the transmission level, the Board directs TransAlta to mirror any TA policies as to waivers of demand ratchet inherent in the TA’s rates. [Section 3(c)] p.57

22. However, the Board also directs TransAlta to adjust the level of the TOU differential in its

Energy Supply charges in the refiling to reflect the Board’s finding in Section 2(a)(1) of this Decision. [Rate 1200 C Section 4(a)(2)(B)] p.69

23. The Board also directs TransAlta to adjust the level of the TOU differential on its Energy

Supply charges in the refiling to reflect the Board’s finding in Section 2(a)(1) of this Decision. [Rate 2500 C Section 4(a)(4)(B)] p.74

24. The Board also directs TransAlta to adjust the level of the TOU differential in its Energy


25. Therefore, the Board directs TransAlta to design a rate along the lines suggested by the

FIRM Customers whereby existing REA irrigation customers are grandfathered in a closed rate that would increase by no more than 10%. The Board approves TransAlta’s design of Rates 2800 to be applicable to new REA irrigation customers only. [Section 4(a)(6)(B)] p.81

26. The Board also directs TransAlta to adjust the level of TOU differential on its Energy


27. The Board also directs TransAlta to adjust the level of the TOU differential on its Energy

Supply charges in the refiling to reflect the Board’s finding in Section 2(a)(1) of this Decision. [Rate 4200 C Section 4(a)(8)(C)] p.85

28. The Board therefore directs TransAlta to make Rate 4100 available to oilfield customers

currently on Rate 290 so that they are able to choose service under Rate 4100, 4400 or 4500. [Section 4(a)(9)(A)] p.87

29. The Board therefore directs TransAlta to include a study, with its PDT filing, that

examines the commonalities and benefits shared between oilfield, general service and farm customers and recommends an appropriate rate class or classes for these customers based on their cost of service characteristics. [Section 4(a)(9)(B)(i)] p.91

30. The Board therefore directs TransAlta to design an additional rate for Oil and Gas

Service, a metered rate similar to Rate 4500 but without the TOU component. [Section Decision U99035 Page 183 10 August 1999


4(a)(9)(B)(ii)] p.96 31. The Board also directs TransAlta to adjust the level of the TOU differential in its Energy

Supply charges in the refiling to reflect the Board’s finding in Section 2(a)(1) of this Decision. [Rate 4500 C Section 4(a)(9)(B)(ii)] p.96

32. The Board directs TransAlta to include this new rate offering at the time of its refiling and

to amend its proposed Rate 4400 to remove its designation as a closed rate. [Section 4(a)(9)(B)(ii)] p.96

33. The Board also directs TransAlta to adjust the level of the TOU differential in its Energy

Supply charges in the refiling to reflect the Board’s finding in Section 2(a)(1) of this Decision. [Rate 6200 C Section 4(a)(10)(D)] p.103

34. Therefore, the Board directs TransAlta to consider only distribution related constraints

when its customers otherwise qualify for temporary energy. [Section 4(a)(11)] p.105 35. Further, the Board directs TransAlta to only curtail energy purchases for distribution

system security reasons or, at the TA’s request, for transmission system reasons. In Section 3(a), the Board directed TransAlta to separate its Delivery Charge into TA Billings and DISCO Services components for all rates.[Section 4(a)(11)] p.105

36. The Board also directs TransAlta to amend its temporary energy rate schedule to allow a

customer to negotiate a temporary rate which flows through the actual pool price if the customer prefers that to negotiating a fixed rate. As the total charges payable by temporary energy customers are negotiated, the Board considers that it would be inappropriate to change the overall rate level payable under this price schedule by including the H credit in the Energy Supply charges. [Section 4(a)(11)] p.105

37. Therefore, the Board directs that TransAlta close the Temporary DAT to new customers

as of the date of this Decision. [Section 4(a)(13)] p.118 38. However, the Board directs TransAlta to design its TOU DAT rate with the following

separated components: • the average actual pool price in each TOU period in 1998 representing the cost of

energy components in the TOU rates, • the fixed amount “H” charge calculated using the 1998 pool price record and 1998

total TransAlta DISCO annual energy usage, and • TA Billings charges which pass through the TOU charges in the TA’s rates. [Section 4(a)(13)] p.120

• •


7. SUMMARY OF BOARD DIRECTIONS TRANSALTA 1996—Phase II • 39. Therefore, the Board directs TransAlta to design its actual pool price DAT rate with the

following separated components: • the actual pool price in each hour less the adjustment amount if the adjustment is

positive as the cost of energy component; • the fixed amount “H” charge calculated using the 1998 pool price record and 1998

total AE DISCO annual energy usage; and • TA Billings charges which pass through the TOU charges in the TA’s rates.

[Section 4(a)(13)] p.121 40. Therefore, the Board directs TransAlta to amend rate schedule 6800 to allow customers to

take only a portion of their load under this rate. [Section 4(a)(13)] p.121 41. Therefore, the Board considers it appropriate to direct that DAT rates include the

provision that notice can be given only after a customer has been on the rate for six months. [Section 4(a)(13)] p.121

42. However, the Board directs TransAlta to provide, at the time of its next Phase II

application, a primary service credit which provides appropriate credits for various voltage levels. [Section 4(b)(1)] p.131

43. Therefore, the Board directs TransAlta to contribute to a maximum investment level of

$1,660 for each new residential underground service and $820 for each new standard overhead service in TransAlta’s service area. [Section 5(a)] p.164

44. Therefore, the Board directs that, for customers served at a single point of delivery at or

above 25 kV, TransAlta’s contract for TA Billings should result in a pass through of all of the terms in TransAlta’s contract with the TA. [Section 5(b)] p.169

45. Therefore, TransAlta is directed to unbundle its investment policy and offer separate

contracts for all of its new or renewing customers for Energy Supply, TA Billings and DISCO Services each with an appropriate minimum term. TransAlta should provide examples of its unbundled contracts with its refiling. [Section 5(b)] p.169

46. The Board therefore, directs TransAlta to review its investment policy and provide at the

PDT proceeding the results of its review including the necessary evidence to support the determined investment levels including the breakdown of the portion of the investment which is for distribution system fixed costs and transmission system costs. [Section 5(b)] p.170

47. The Board directs TransAlta to provide, in its refiling, a calculation of its interest refund



and a proposed rider to refund the interest to customers. [Section 6(a)] p.177



8. ORDER

Therefore, it is ordered that: (1) TransAlta Utilities Corporation shall refile its proposed Rates and Options and its Terms

and Conditions of Electric Service, on or before 1 September 1999, incorporating the findings of the Board in this Decision.

(2) TransAlta Utilities Corporation, in its refiling, shall include a cost of service study

incorporating the findings of the Board in this Decision (3) TransAlta Utilities Corporation, in its refiling, shall include the revenue-to-cost ratios for

each rate by cost source (Energy Supply, TA Billings and DISCO Services). DATED in Calgary, Alberta on 10 August 1999. ALBERTA ENERGY AND UTILITIES BOARD J. P. Prince, Ph.D. Presiding Member B. T. McManus, Q.C. Member H. Jainarine, FCCA Acting Member


APPENDIX 1

PARTIES PARTICIPATING IN THE PROCEEDING

APPEARANCES AND INTERESTED PARTIES

TransAlta Utilities Corporation (TransAlta) Mr. C. L. Clarke Mr. J. J. Marshall Ms. B. Ho

Alberta Power Limited (APL) Mr. L. G. Keough

Edmonton Power Inc. (EPI) Mr. J. M. Liteplo

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

Mr. A. L. McLarty

Alberta Irrigation Projects Association (AIPA) Mr. J. H. Unryn

Amoco Energy Management Services–Canada (Amoco) Mr. C. K. Yates Ms. M. Buchinski

Alberta Association of Municipal Districts and Counties (AAMDC)

Mr. P. G. Sully, Q.C. Ms. J. Grundberg

Alberta Federation of REAs Ltd. (REA) Mr. K. L. Sisson

Consumers Coalition of Alberta (CCA) Mr. J. A. Wachowich

The Canadian Cable Television Association (CCTA) Mr. R. B. White

Enmax Corporation (Enmax) Mr. R. B. Brander

ESBI Alberta Ltd. (EAL) Mr. G. Rogers

Husky Oil Operations Limited (Husky)

Industrial Power Consumers Association of Alberta (IPCAA)

Mr. D. E. Crowther


APPENDIX 1 C PARTIES PARTICIPATING IN THE PROCEEDING APPEARANCES AND INTERESTED PARTIES

Independent Power Producers Society of Alberta (IPPSA)/ Senior Petroleum Producers Association (SPPA)

Mr. L. L. Manning

Municipal Intervenors (MI) Mr. J. A. Bryan, Q.C.

Public Institutional Consumers of Alberta (PICA) Ms. N. J. McKenzie

Shaw Cable Systems G.P. (Shaw) Mr. R. B. White

Ms. Tara DeLeeuw

TransCanada Energy Ltd. (TransCanada) Ms. B. Andriachuk

Town of Ponoka; Town of Pincher Creek; Municipal District of Pincher Creek

Mr. B. Dodd

TELUS Corporation (TELUS)


APPENDIX 1 C PARTIES PARTICIPATING IN THE PROCEEDING

WITNESSES

TransAlta Utilities Corporation Mr. J. J. Martin

Mr. A. Reimer Mr. T. J. Barnett

Albchem Industries Ltd., CXY Chemicals and Down Chemical Canada Inc.

Mr. P. J. Lanzalotta Mr. K. Kohler Mr. P. Kos

Independent Power Producers Society of Alberta and Senior Petroleum Producers Association

Mr. R. D. Knecht

Senior Petroleum Producers Association Mr. K. Wilford Mr. D. Hildebrand Mr. C. Samuels Mr. J. Clark

Industrial Power Consumers Association of Alberta Mr. M. Drazen Ms. L. Pearson Ms. B-S. Hoffman Mr. R. Gallant Mr. D. B. Macnamara Mr. R. R. Steffan Mr. C. A. Jager

The FIRM Customers Mr. W. B. Marcus

Alberta Federation of REAs Ltd. Mr. W. B. Marcus Mr. M. G. Davies

South Alta Rural Electrification Association Ltd. Ms. C. Van Buren


APPENDIX 2

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)

AECO-C Alberta Energy Company’s monthly weighted average gas price paid for gas purchased from their “C” Gas Storage Hub

AIPA Alberta Irrigation Projects Association

AIS Alberta Interconnected System

Amoco Amoco Energy Management Services–Canada

APL Alberta Power Limited (now ATCO Electric Ltd.)

AR Alberta Regulation

Board or AEUB Alberta Energy and Utilities Board

Cable Intervenors Shaw Communications Inc. and The Canadian Cable Television Association

CCA Consumers Coalition of Alberta

COSS Cost of Service

CWNG Canadian Western Natural Gas Company Limited

DAT Direct Access Tariff

DCGI Drazen Consulting Group, Inc.

DISCO Distribution Company

DOS DISCO Opportunity Service

EAL or ESBI ESBI Alberta Limited

EEMA Electric Energy Marketing Agency

EU Act Electric Utilities Act

Decision U99035 Page192 10 August 1999

APPENDIX 2 C ABBREVIATIONS

EUA Act Electric Utilities Amendment Act

FIRM Customers Alberta Association of Municipal Districts and Counties, Alberta Federation of REAs Ltd., Alberta Irrigation Projects Association, Consumers Coalition of Alberta, Municipal Intervenors and Public Institutional Consumers of Alberta

GAC Generation Access Charge

GENCO Generation Company

GIS Grid Interconnection Service

GOS Grid Opportunity Service

GRA General Rate Application

GSS Grid Standard Service

GTA General Tariff Application

IPCAA Industrial Power Consumers Association of Alberta

IPPSA Independent Power Producers Society of Alberta

kVAR Kilovolt ampere reactive

MI Municipal Intervenors

MTS Manitoba Telephone Service

MVA Mega volt amperes

NCP Non-Coincident Peak

NGTL Nova Gas Transmission Ltd.

O&M Operating and Maintenance

PDT Preliminary Distribution Tariff

PICA Public Institutional Consumers of Alberta

POD Point of Delivery


APPENDIX 2 C ABBREVIATIONS

POR Pool Opportunity Rate

PUB Act Public Utilities Board Act

R/C Ratio Revenue-to-cost ratio

REA Alberta Federation of REAs Ltd.

RFP Request for proposal

RP Reservation price

SaskPower Saskatchewan Power Corporation

SC/RV Stranded cost/residual value

Shaw Shaw Cable Systems G.P.

SPPA Senior Petroleum Producers Association

TA Transmission Administrator

TDAT Temporary Direct Access Tariff

TELUS TELUS Corporation

TOU Time-of-use

TransAlta TransAlta Utilities Corporation

TransCanada TransCanada Energy Ltd.

TRANSCO Transportation Company

TRR Totalization Rate Rider

UOA Unit Obligation Amount

UOP Unit Obligation Price

UOV Unit Obligation Value

3W/9NW 3 winter/9 non-winter months


APPENDIX 3

REFERENCES

ORDER/ DECISION/ REPORT NO.

DATE

PARTICULARS

E94076 4 November 1994 TransAlta Utilities Corporation (Decision –Network Services and Generation Services Rates)

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

U96001 24 January 1996 NOVA Gas Transmission Ltd. (Decision – 1995 General Rate Application –Phase I)

U96053 15 August 1996 TransAlta Utilities Corporation (Order – Interim Approval of Rate Options 12 and 21)

U96077 1 October 1996 TransAlta Utilities Corporation (Order B Amend the Terms and Conditions of Electric Service)

U97065 31 October 1997 Alberta Power Limited, Edmonton Power Inc., TransAlta Utilities Corporation and Grid Company of Alberta (Decision – 1996 Electric Tariff Application)

U97156 19 December 1997 TransAlta Utilities Corporation, Alberta Power Limited, Edmonton Power Inc., and Grid Company of Alberta (Decision –Approval on certain prices and tariffs, pursuant to section 75 of the Electric Utilities Act)

U98029 30 January 1998 TransAlta Utilities Corporation (Decision – 1997 Tariff Application)


APPENDIX 3 C REFERENCES

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

U98124 12 August 1998 TransAlta Utilities Corporation (Order – Investigation of 1995 Rates)

U98193 24 December 1998 TransAlta Utilities Corporation (Decision– Final adjustments to 1998 tariffs and approval on interim refundable basis for certain 1999 tariffs)

U99015 8 February 1999 TransAlta Utilities Corporation (Decision – 1996 General Rate Application – Phase II Temporary Direct Access Tariff)

U99018 11 February 1999 ESBI Alberta Ltd. (Order B 1999 tariffs on an interim refundable basis)

U99026 4 March 1999 TransAlta Utilities Corporation (Decision – 1996 General Rate Application -- Phase II Option F – Planned Interruption Option)


APPENDIX 4

HOW THE RP ALLOCATION METHOD MAY DISTORT THE POOL PRICE SIGNAL

Page 1 of 2

VARIATION FROM PRIOR HOUR: HOURLY GENERATION COST ALLOCATION TO CUSTOMER USING: IN PP IN GENERATION COST ALLOCATION Assuming that Load = Called Entitlements TRANSALTA’S PROPOSED METHODS BOARD METHOD TRANSALTA TRANSALTA BOARD Example TAU Method (For any ratio of

Example Pool Reservation Example L 10%<Centitlem L=Centitlem L 10%>Centitlem Load/Centitlem) (Assuming (Assuming that (For any ratio of Hours Price Payment AVG UOP UOV ALL CLASSES ALL CLASSES ALL CLASSES ALL CLASSES L=Centitlem L 10%>Centitlem Load/Centitlem)

(PP) (AvgRP*UOV/AvgUOV) (Estimates) (PP-UOP) PP+1.11*(RP-UOV) (PP+RP-UOV) PP+.909*(RP-UOV) (PP+Avg RP- Avg UOV) In each hour) In each hour) (19.69*e/26.55) (b-d) (b+1.11*(c-e)) (b+c-e) (b+.909*(c-e)) (b+19.69-26.55)

(a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m)$/MWh $/MWh $/MWh $/MWh $/MWh $/MWh $/MWh $/MWh $/MWh $/MWh $/MWh $/MWh

1 32.00 20.77 4.00 28.00 23.97 24.77 25.42 25.14

2 40.00 25.59 5.50 34.50 30.11 31.09 31.90 33.14 8.00 6.32 6.47 8.00

3 20.00 12.24 3.50 16.50 15.27 15.74 16.12 13.14 -20.00 -15.35 -15.77 -20.00

4 100.00 69.71 6.00 94.00 73.04 75.71 77.92 93.14 80.00 59.98 61.80 80.00

5 500.00 366.36 6.00 494.00 358.32 372.36 383.98 493.14 400.00 296.65 306.05 400.00

6 50.00 32.63 6.00 44.00 37.38 38.63 39.67 43.14 -450.00 -333.73 -344.31 -450.00

Annual Avg 31.25 19.69 4.70 26.55 23.64 24.39 25.01 24.39 -18.75 -14.24 -14.65 -18.75 Example

31.25 19.69 4.70 26.55 DEFINITIONS:

Board’s “H” FACTOR -6.86 Centitlem= hour’s called entitlements H= Forecast annual DISCO RP- Forecast Disco total annual UOV refund L= hour’s load

Forecast Disco annual energy use

PP= hour’s pool price AVG UOP= estimated MWh weighted average UOP of units running in the hour

H= Annual Avg RP - Annual Avg UOV = 19.69 - 26.55 = - 6.86

Annual Avg UOV= total forecast annual Disco UOV/total forecast Disco annual energy use Annual Avg RP= total forecast annual Disco RP/total forecast Disco annual energy use “H” Factor= Annual Avg RP - Annual Average UOV Generation Cost= pool price plus net value of legislated hedges

This Attachment illustrates how variation in the generation cost allocated to customers does not match variation in the pool price signal when RP is allocated per TransAlta’s UOV based energy method (Column(c)). Column (c) shows how the RP allocated would be higher in high PP hours (Column (b)). As a result TransAlta’s method (Columns (k)&(l)) results in a distortion, since the generation cost allocated does not vary directly with variation in the pool price signal (Column (j)). The Board’s method (Column (m)) using the “H” Factor (H = annual avg RP-annual avg UOV) the variation in the generation cost allocated equals the variation in the pool price signal. (i.e. In hour 2 the pool price has increased from $32 to $40 or by $8, but the generation cost allocated under TransAlta’s method would increase by $6.32 or $6.14 (depending on the ratio of load to called entitlements and assuming that ratio remained constant). Under the Board’s method (Column (m)) the variation in hourly pool price would be exactly matched by the increase in generation cost allocated.) The annual average RP and UOV and the hourly PP and average UOP are numbers provided to illustrate the principles demonstrated herein and are not necessarily representative.


APPENDIX 4 C HOW THE RP ALLOCATION METHOD MAY DISTORT THE POOL PRICE SIGNAL

Explanation of column: Page 2 of 2 (a) example hour (b) example pool price per MWh in example hour (c) calculated RP per MWh allocated to the example hour: using TransAlta’s allocation method RP = (Avg Annual RP)*(Hour’s Forecast UOV)/(Avg Annual UOV) (d) estimated MWh weighted average UOP of the units running in the example hour per Mwh estimated AVG UOP=sum of each called unit’s UOA*(that unit’s UOP)/(sum of all units’ called UOAs) (e) calculated UOV per MWh in example hour if load is equal to called entitlements UOV = PP - AVG UOP (f) calculated total generation cost per MWh to be allocated to customer if the load is 10% less than the called entitlements in the hour using

TransAlta’s allocation methods Generation Cost = Hours Load *PP + 1.11*(Hour’s Load)*RP - 1.11*(Hour’s Load)*UOV = PP +1.11*RP - 1.11*UOV Hour’s Load (g) calculated total generation cost per MWh to be allocated to customer if the load is equal to the called entitlements in the hour using TransAlta’s

allocation methods Generation Cost = Hour’s Load *PP + (Hour’s Load)*RP - *(Hour’s Load)*UOV = PP + RP - UOV Hour’s Load (h) calculated total generation cost per MWh to be allocated to customer if the load is 10% greater than the called entitlements in the hour using

TransAlta’s allocation methods Generation Cost = Hour’s Load *PP + .909*(Hour’s Load)*RP - .909*(Hour’s Load)*UOV = PP +.909*RP - .909*UOV

Hour’s Load (i) calculated total generation cost per MWh to be allocated to customer for any ratio of load to called entitlements using Board’s allocation method

Generation Cost = PP + H (j) calculated variation from the prior hour in the pool price

Variation = (PP in prior hour) - (PP in hour) (k) calculated variation from the prior hour in the total generation cost per MWh allocated, if the load is assumed to be equal to the called entitlements

in each hour, using TransAlta’s allocation methods Variation = (Generation Cost in prior hour) - (Generation cost in hour) (l) calculated variation from the prior hour in the total generation cost per MWh allocated, if the load is assumed to be 10% greater than the called

entitlements in each hour, using TransAlta’s allocation methods Variation = (Generation Cost in prior hour) - (Generation cost in hour) (m) calculated variation from the prior hour in the total generation cost per MWh allocated for any ratio of load to called entitlements using Board’s

allocation method Variation = (Generation Cost in prior hour) - (Generation cost in hour)


APPENDIX 5

HOW THE METHOD OF ALLOCATION OF UOV REFUNDS MAY DISTORT THE POOL PRICE SIGNAL

Page 1 of 2

VARIATION FROM PRIOR HOUR: HOURLY GENERATION COST ALLOCATION TO CUSTOMERS USING: IN PP IN GENERATION COST ALLOCATION Assuming that Load = Called Entitlements TRANSALTA’S PROPOSED METHODS BOARD METHOD TRANSALTA TRANSALTA BOARD

Example Example Pool Reservation Example L 10%<Centitlem L=Centitlem L 10%>Centitlem Any Load/Centitlem (Assuming (Assuming that (For any ratio of

Hours Price Payment AVG UOP UOV ALL CLASSES ALL CLASSES ALL CLASSES ALL CLASSES L=Centitlem L 10%>Centitlem Load/Centitlem)(PP) (Set to 0) (Estimates) (PP-UOP) PP+1.11*(RP-UOV) (PP+RP-UOV) PP+.909*(RP-UOV) (PP+Avg RP- Avg UOV) In each hour) In each hour)

(b-d) (b+1.11*(c-e)) (b+c-e) (b+.909*(c-e)) (b+0-26.55)

(a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k) (l) (m)$/MWh $/MWh $/MWh $/MWh $/MWh $/MWh $/MWh $/MWh $/MWh $/MWh $/MWh $/MWh

1 32.00 0.00 4.00 28.00 0.92 4.00 6.55 5.45

2 40.00 0.00 5.50 34.50 1.71 5.50 8.64 13.45 8.00 1.50 2.09 8.00

3 20.00 0.00 3.50 16.50 1.69 3.50 5.00 -6.55 -20.00 -2.00 -3.64 -20.00

4 100.00 0.00 6.00 94.00 -4.34 6.00 14.55 73.45 80.00 2.50 9.55 80.00

5 500.00 0.00 6.00 494.00 -48.34 6.00 50.95 473.45 400.00 0.00 36.40 400.00

6 50.00 0.00 6.00 44.00 1.16 6.00 10.00 23.45 -450.00 0.00 -40.95 -450.00

Annual Avg 31.25 0.00 4.70 26.55 1.78 4.70 7.12 4.70 -18.75 -1.30 -2.89 -18.75 Example

31.25 0.00 4.70 26.55 DEFINITIONS:

Board’s “H” FACTOR -26.55 Centitlem= hour’s called entitlements H= Forecast annual Disco RP- Forecast Disco total annual UOV refund L= hour’s load

Forecast Disco annual energy use

PP= hour’s pool price AVG UOP= estimated MWh weighted average UOP of units running in the hour

H= Annual Avg RP - Annual Avg UOV = 0 - 26.55 = - 26.55

Annual Avg UOV- total forecast annual Disco UOV/total forecast Disco annual energy use Annual Avg RP= total forecast annual Disco RP/total forecast Disco annual energy use “H” Factor= Annual Avg RP - Annual Average UOV Generation Cost= pool price plus net value of legislated hedges

This Attachment illustrates how variation in the total cost of generation does not match variation in the pool price under TransAlta’s method of allocating the UOV. The RP is set to 0 (Column (c)) so that the distortion caused can be clearly seen. Use of TransAlta’s UOV allocation method (Columns (k)&(l)) results in a distortion since the variation in generation cost allocated is not equal to the variation in the pool price signal (Column (j)). Under the Board’s method (Column (m)) using the “H” Factor (H = annual avg RP-annual avg UOV) the variation in generation cost allocated is equal to the variation in the pool price signal. (i.e. In hour 2 the pool price has increased from $32 to $40 or by $8, but the generation cost allocated under TransAlta’s method would increase by $6.32 or $6.14 (depending on the ratio of load to called entitlements and assuming that ratio remained constant). Under the Board’s method (Column (m)) the increase in pool price would be exactly matched by the increase in generation cost allocated regardless of the ratio of load to called entitlements in either hour.) The annual average RP and UOV and the hourly PP and average UOV are numbers used to illustrate the principles demonstrated herein and not necessary representative.


APPENDIX 5 C HOW THE METHOD OF ALLOCATION OF UOV REFUNDS MAY DISTORT THE POOL PRICE SIGNAL

Explanation of column:

Page 2 of 2

(a) example hour (b) example pool price per MWh in example hour (c) RP has been set to zero to so as not to mask the effect of the UOV allocation methods (d) estimated MWh weighted average UOP of the units running in the example hour per MWh estimated AVG UOP=sum of each called unit’s UOA*(that unit’s UOP)/(sum of all units’ called UOAs) (e) calculated UOV per MWh in example hour if load is equal to called entitlements UOV = PP - AVG UOP (f) calculated total generation cost per MWh to be allocated to customer if the load is 10% less than the called entitlements in the hour using

TransAlta’s allocation methods Generation Cost = Hour’s Load *PP + 1.11*(Hour’s Load)*RP - 1.11*(Hour’s Load)*UOV = PP + 1.11*RP - 1.11*UOV

Hour’s Load (g) calculated total generation cost per MWh to be allocated to customer if the load is equal to the called entitlements in the hour using TransAlta’s

allocation methods Generation Cost = Hour’s Load *PP + (Hour’s Load)*RP - *(Hour’s Load)*UOV = PP + RP - UOV Hour’s Load (h) calculated total generation cost per MWh to be allocated to customer if the load is 10% greater than the called entitlements in the hour using

TransAlta’s allocation methods Generation Cost = Hour’s Load *PP + .909*(Hour’s Load)*RP - .909*(Hour’s Load)*UOV = PP +.909*RP - .909*UOV

Hour’s Load (i) calculated total generation cost per MWh to be allocated to customer for any ratio of load to called entitlements using Board’s allocation method

Generation Cost = PP + H (j) calculated variation from the prior hour in the pool price

Variation = (PP in prior hour) - (PP in hour) (k) calculated variation from the prior hour in the total generation cost per MWh allocated, if the load is assumed to be equal to the called entitlements

in each hour, using TransAlta’s allocation methods Variation = (Generation Cost in prior hour) - (Generation cost in hour) (l) calculated variation from the prior hour in the total generation cost per MWh allocated, if the load is assumed to be 10% greater than the called

entitlements in each hour, using TransAlta’s allocation methods Variation = (Generation Cost in prior hour) - (Generation cost in hour) (m) calculated variation from the prior hour in the total generation cost per MWh allocated for any ratio of load to called entitlements using Board’s

allocation method Variation = (Generation Cost in prior hour) - (Generation cost in hour)


APPENDIX 6

COMPARISON OF DISTRIBUTION INVESTMENT LEVEL PROPOSALS

TransAlta Proposed IPPSA/SPPA Proposed

Maximum Investment Levels Investment Levels Difference

$667 on first 300 kW $850 on first 75 kW $167 on each additional kW on next 925 kW

$125 on remaining kW

Max Demand

Maximum Cost Max Demand

Maximum Cost IPPSA/SPPA

in KW Investment per kW in KW Investment per kW over/(under)TransAlta

5 $3,335 667 5 4,250 850 915 25 $16,675 667 25 21,250 850 4,575 50 $33,350 667 50 42,500 850 9,150 75 $50,025 667 75 63,750 850 13,725

100 $66,700 667 100 75,000 750 8,300 125 $83,375 667 125 86,250 690 2,875 138 $92,046 667 138 92,100 667 54 150 $100,050 667 150 97,500 650 -2,550 175 $116,725 667 175 108,750 621 -7,975 200 $133,400 667 200 120,000 600 -13,400 225 $150,075 667 225 131,250 583 -18,825 250 $166,750 667 250 142,500 570 -24,250 275 $183,425 667 275 153,750 559 -29,675 300 $200,100 667 300 165,000 550 -35,100 400 $216,800 542 400 210,000 525 -6,800 424 $220,808 521 424 220,800 521 -8 500 $233,500 467 500 255,000 510 21,500 600 $250,200 417 600 300,000 500 49,800 700 $266,900 381 700 345,000 493 78,100 800 $283,600 355 800 390,000 488 106,400 900 $300,300 334 900 435,000 483 134,700

1,000 $317,000 317 1,000 480,000 480 163,000 1,500 $400,500 267 1,500 542,500 362 142,000 2,000 $484,000 242 2,000 605,000 303 121,000 2,500 $567,500 227 2,500 667,500 267 100,000 3,000 $651,000 217 3,000 730,000 243 79,000 4,881 $965,127 198 4,881 965,125 198 -2

$450


Documents

U99035 Decision: TransAlta Utilities Corporation 1996 ...€¦ · commencing 1 January 1996 in Order E95123, dated 21 December 1995. In Decision U97156, dated 19 December 1997, the