DECISION 2002-026
2000 POOL PRICE DEFERRAL ACCOUNTS PROCEEDING
PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS
(April 18, 2002)
ALBERTA ENERGY AND UTILITIES BOARD 2000 Pool Price Deferral Accounts Proceeding
2000 POOL PRICE DEFERRAL ACCOUNTS PROCEEDING
PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS
CONTENTS
1 INTRODUCTION...... 1
2 BACKGROUND & GENERAL COMMENTS ...... 2
3 BOARD DETERMINATION OF ALLOCATION METHODOLOGY ...... 5 3.1 Analytical Framework ...... 5 3.2 PPDA Formulae...... 6 3.3 Principles...... 7 3.4 Exclusion of Classes from PPDA Allocation ...... 9 3.5 Derivation of DISCO UOV Refunds ...... 11 3.6 Assessment of Proposed Methodologies ...... 12 3.7 Board Determination of a Cost-Based Allocation Methodology...... 16 3.7.1 Rate Class Pool Purchase Deficiency ...... 16 3.7.1.1 Board Template ...... 16 3.7.1.2 “Actual” Class Pool Purchase Costs ...... 17 3.7.1.3 “Actual” Class Pool Purchase Revenues...... 18 3.7.1.4 Method of Determining Pool Purchase Deficiency...... 19 3.7.2 UOV Refunds By Rate Class...... 21 3.7.2.1 Actual Class UOV Refunds...... 21 3.7.2.2 Actual UOV Refunds Received by Classes ...... 23 3.7.2.3 Method of Determining Outstanding UOV Refunds Due to Classes...... 23 3.7.3 Allocation of Net PPDA Deficiency...... 24
4 ASSESSMENT OF BOARD DETERMINED COST-BASED METHODOLOGY .. 25 4.1 Introduction...... 25 4.2 Fairness Considerations (General)...... 26 4.2.1 Total Final 2000 Economics and Energy Unit Costs...... 26 4.2.2 Review of Rate Design for 2000...... 27 4.2.3 Maintaining 2000 Price Signals & Relationships Among Rates ...... 36 4.2.4 Fairness Within Customer Classes...... 41 4.2.5 Use of 2000 Rate Design Principles ...... 41 4.2.6 Impact of Demand Side Response on UOV Allocation...... 43 4.3 Fairness Considerations (Option G)...... 47 4.3.1 Introduction...... 47 4.3.2 Board Jurisdiction respecting Option G Rates...... 48 4.3.3 Board Review of Other Option G Fairness Concerns...... 49 4.3.4 Board Determination of Option G System Benefits ...... 54 4.4 Fairness Considerations (DAT) ...... 56 4.5 Fairness of the Allocation of DAT and Option G UNCA PPDA Adjustment...... 57
EUB Decision 2002-026 (April 18, 2002) • i
ALBERTA ENERGY AND UTILITIES BOARD 2000 Pool Price Deferral Accounts Proceeding
4.6 Board Conclusions...... 59
5 ALLOCATION TO RATE CLASSES OF GENCO COMPONENTS PASSED THROUGH TO DISCOS ...... 59 5.1 Introduction...... 59 5.2 Allocation of GENCO Deferrals to DAT ...... 60 5.2.1 Introduction...... 60 5.2.2 Views of Interested Parties ...... 60 5.2.3 Views of the Board - Allocation of GENCO Deferrals to DAT Customers ...... 62 5.3 GENCO Generation and Ancillary Service Deferrals ...... 63 5.3.1 Views of Interested Parties ...... 63 5.3.2 Views of the Board - GENCO Generation and Ancillary Service Deferrals ...... 66 5.4 GENCO STS Claims...... 67 5.4.1 Introduction...... 67 5.4.2 Views of the Board - GENCO STS Claims...... 68 5.5 Keephills and Wabamun TSR Adjustments ...... 68 5.5.1 Introduction...... 68 5.5.2 Views of the Board - Keephills and Wabamun TSR Adjustments...... 68 5.6 Miscellaneous GENCO Amounts...... 69 5.6.1 Views of Interested Parties ...... 69 5.6.2 Views of the Board - Miscellaneous GENCO Amounts ...... 70
6 VIEWS OF THE BOARD - ALLOCATION REFILINGS ...... 70
7 SUMMARY OF KEY FINDINGS...... 71
8 SUMMARY OF DIRECTIONS...... 73
APPENDIX 1 - RELEVANT DECISIONS - 2000 DEFERRAL ACCOUNTS...... 77
APPENDIX 2 - BOARD ALLOCATION TEMPLATE ...... 81
APPENDIX 3 - AE DISCO DEFERRAL ACCOUNTS...... 83
APPENDIX 4 - CALCULATION OF OPTION G SYSTEM BENEFITS AND OPTION G/DAT POOL PURCHASE COSTS ...... 85
APPENDIX 5 – VIEWS OF THE PARTIES REGARDING APPROPRIATENESS OF INCLUDING DAT AND OPTION G CLASSES IN THE ALLOCATION ...... 87 Views of IPCCAA ...... 89 Views of FIRM ...... 93 Views of ANC/MW ...... 93 Views of UNCA...... 104 UNCA Response to IPCCAA ...... 105 UNCA Response to ANC/WM...... 106
ii • EUB Decision 2002-026 (April 18, 2002)
ALBERTA ENERGY AND UTILITIES BOARD 2000 Pool Price Deferral Accounts Proceeding
APPENDIX 6 - VIEWS OF THE PARTIES RESPECTING PPDA ALLOCATIONS TO RATE CLASS...... 109 1.1 Views of UNCA...... 109 1.2 Views of AE DISCO...... 112 1.3 Views of IPCCAA ...... 116 1.4 Views of FIRM ...... 145 1.5 Views of AIPA...... 155 1.6 Views of SPPA ...... 164
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ALBERTA ENERGY AND UTILITIES BOARD 2000 Pool Price Deferral Accounts Proceeding
LIST OF TABLES Table 1: Actual Annual Load Characteristics Rates 6300 and 6400 ...... 54
Table 2: Option G Load Characteristics (Jan. 1 – Aug. 31/2000)...... 55
Table 3: GENCO Components Passed Through to UNCA (per IPCCAA) ...... 60
Table 4: Allocation of GENCO Deferrals to UNCA Rate Class (per IPCCAA)...... 64
Table 5: Graph Showing UNCA Share of 2000 GENCO Deferral (Per IPCCAA)...... 65
Table 6: Miscellaneous GENCO Amounts for UNCA (per IPCCAA) ...... 69
Table 7: List of 2000 Deferral Account Related Decisions ...... 77
Table 8: UNCA Average Pool Purchase Cost by Class (per IPCCAA)...... 118
Table 9: Difference between an hourly and monthly UOV refund (Per IPCCAA) ...... 121
Table 10: Hourly Allocation of Pool Price and UOV Refund (Per IPCCAA) ...... 122
Table 11: IPCCAA Comparison Pool Price and UOV Components Only...... 124
Table 12: IPCCAA Comparison Pool Price and UOV Components (Per Unit)...... 125
Table 13: Expected Average Cost of Hot Dogs (Per IPCCAA)...... 129
Table 14: Actual Average Cost of Hot Dogs With Equal Coupons (Per IPCCAA) ...... 130
Table 15: Actual Average Cost of Hot Dogs With Hourly Allocation (IPCCAA)...... 130
Table 16: Hourly Allocation of Pool Price and Monthly UOV Refund (IPCCAA)...... 131
Table 17: Hourly Allocation of Pool Price and Monthly UOV Refund (IPCCAA)...... 132
Table 18: Comparison of Rate Class Allocations (IPCCAA) ...... 137
Table 19: Comparison of Rate Class Allocations ($/MWh) (IPCCAA) ...... 138
Table 20: Average Power Pool Purchase Cost $/MWh (IPCCAA)...... 140
Table 21: Allocation Amounts to Irrigation Service (Per AIPA)...... 161
iv • EUB Decision 2002-026 (April 18, 2002)
IMPORTANT NOTE TO ELECTRONIC READERS:
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Table of Contents List of Tables Page 1 of the Decision
Appendix 1 Appendix 1 - Relevant Decisions - 2000 Deferral Accounts Appendix 2 Board Allocation Template Appendix 3 AE DISCO DEFERRAL ACCOUNTS Appendix 4 Calculation of Option G system benefits and Option G/DAT pool purchase costs Appendix 5 VIEWS OF THE PARTIES re including DAT and Option G classes in allocation Appendix 6 Views of the parties respecting allocations to rate class
To Go Directly to Views of the Board
Board determination of allocation methodology Analytical Framework PPDA Formulae Principles Exclusion of Classes from PPDA Allocation Derivation of DISCO UOV Refunds Assessment of Proposed Methodologies Board Determination of a Cost-Based Allocation Methodology Assessment of Board determined Cost-based methodology Fairness Considerations (General) Fairness Considerations (Option G) Fairness Considerations (DAT) Fairness of the Allocation of DAT and Option G UNCA PPDA Adjustment to UNCA PPDA Allocation to Rate Classes of GENCO components passed through to DISCOs
To Go Directly To Board Approved Summaries:
Allocation Refilings Summary of Key Findings Summary of Directions
EUB Decision 2002-026 (April 18, 2002) • i
ALBERTA ENERGY AND UTILITIES BOARD Calgary, Alberta
2000 POOL PRICE DEFERRAL ACCOUNTS Decision 2002-026 PART R: AE DISCO & UNCA DISCO Application Nos. 1257787 & 1257784 ALLOCATION TO RATE CLASS File Nos. 1108-8-2 & 1900-5-2
1 INTRODUCTION
On March 30, 2001, ATCO Electric Ltd. (AE or AE DISCO) and UtiliCorp Networks Canada (Alberta) Ltd. (UNCA or UNCA DISCO) filed applications (the DISCO Applications) with the Alberta Energy and Utilities Board (Board) in which they submitted for approval the closing balances of their 2000 pool price deferral accounts (Deferral Accounts or PPDAs) as of December 31, 2000 and for a determination of the amount payable to AE and UNCA in respect of the cost of financing the amounts in their Deferral Accounts.
The AE DISCO Deferral Accounts were established in the Alberta Power Limited 1999/2000 Tariff Application Phase 1 Negotiated Settlement (1999/2000 Settlement) approved by the Board in Decision U99046.1
UNCA’s Deferral Account was originally established by the Board for TransAlta in Decision U99099 and clarified in Decision 2000-3. Pursuant to the conditions attached to the Board’s approval of the sale by TransAlta to UNCA of TransAlta DISCO, UNCA inherited TransAlta DISCO’s Deferral Account as established by the Board.2 These Board-approved Deferral Accounts comprise the “deferral accounts” for AE DISCO and UNCA as defined in the Deferral Accounts Deficiency Correction Regulation (Deferral Accounts Regulation).3
The Board heard the Final Applications of AE DISCO and UNCA, as well as applications from four municipally owned DISCOs and three GENCOs, in an omnibus hearing that commenced June 4, 2001 and ended July 30, 2001 (2000 Pool Price Deferral Accounts Proceeding or PPDA Proceeding).4
On December 4, 2001, the Board issued Decisions 2001-88 (ENMAX), 2001-89 (EDI), 2001-90 (Red Deer) and 2001-91 (Lethbridge) respecting the Board’s review of the municipally-owned DISCOs. On December 12, 2001, the Board issued Decision 2001-92, in which it decided generic carrying cost, recovery period and hedging issues for all six DISCOs.
The Board issued Decision 2001-93 on December 22, 2001, dealing jointly with the AE DISCO and UNCA PPDA balances. In Decision 2001-93, the Board approved the AE DISCO and
1 The 1999/2000 Settlement was made under AE’s former name of Alberta Power Limited (APL). 2 See Decision 2000-41, TransAlta Utilities Corporation, Sale of Distribution Business (July 5, 2000). 3 AR 240/2000, as amended by AR 6/2001. 4 The Board also dealt with a number of non-pool price related deferral account matters outstanding from year 2000 pursuant to a written proceeding. These Outstanding Matters Accounts (OMA) Applications were initially dealt with by the Board in Decision 2001-82 (GENCOs) and 2001-83 (DISCOs), with refilings dealt with in Decisions 2001-114, 2002-003, 2002-006, 2002-007 and 2002-023.
EUB Decision 2002-026 (April 18, 2002) • 1
PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding
UNCA PPDA balances and indicated that it would deal with the allocation of the approved balances to rate class in a forthcoming Decision following receipt of the DISCO refilings.
Decisions 2002-023 and 2002-024, issued April 2, 2002, dealt with the DISCO OMA and PPDA Refilings, respectively. In those Decisions, the Board has directed further refilings from AE DISCO and UNCA that are due on April 29, 2002.
In this Decision, the Board will determine the appropriate methodology to allocate balances in the AE DISCO and UNCA PPDAs to customer/rate classes. In addition, the appropriate methodology to allocate certain approved GENCO deferral amounts passed through to each DISCO will be addressed in Section 5.
The Board notes that, while the size of the deferral accounts has increased the importance of grouping customers correctly for allocation purposes, the proliferation of rates and rate options increased the difficulty of appropriately describing groups of rate classes and rate options. In this Decision, the Board has used the terms “class”, “customer class” and “rate class” interchangeably. However, depending on the context, some explanation of the Board’s approach is required.
Traditionally a “customer class” referred to the combination of certain related rate classes. For the purposes of this Decision, the Board has found it more appropriate to include Time of Use (TOU) rate class and fixed rate class, and all rate options (aside from Option G) available to those classes, within the same traditional customer class. However, the DAT rate classes (with customers from all former traditional customer classes) and Option G customers (from Rate 6300 and Rate 6400) are excluded from the “traditional” customer class, each instead forming a separate customer class for purposes of this Decision.
The Board received refilings from AE DISCO and UNCA dealing with both OMAs and PPDAs. The last of these refilings was received on March 1, 2002. The last comments in relation to these refilings were received on March 4, 2002. Therefore, the Board considers March 4, 2002, to be the date on which the record closed for the purpose of this Decision.
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2 BACKGROUND & GENERAL COMMENTS
The Board determined the rates that were applicable in the year 2000 in a number of related Decisions. The rates were completely redesigned following the 1996 Phase II proceeding and were implemented on March 1, 2000. In a later section of this Decision, the Board provides a complete review of these past Decisions outlining the framework for the rates effective in the period March to December 2000 when the bulk (about 95%) of the net DISCO PPDA and GENCO deferral account balances accumulated.
Typically, once the Board sets utility rates on a forecast basis, the utility would be responsible for any variance from forecast of its costs to serve customers and of the revenues realized from the approved rates. The price signals to customers implicit in the rates would remain unchanged
2 • EUB Decision 2002-026 (April 18, 2002)
PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding
notwithstanding the variance from forecast. However, Decisions U99046 and U99099 established PPDAs that allow the DISCOs to recover the net deferral account balances from customers. When deferral accounts are established, the economics implicit in the rates that applied over the test year period are subject to the eventual disposition of the deferral accounts after the period ends.
In this instance, at the time the deferral accounts were originally approved as part of the DISCOs’ rate structures, the Board did not establish how the net balances would ultimately be allocated to customers. In addition, while the purpose of the deferral accounts at the DISCO level was to capture the pool price variance from forecast at the actual volume served by the DISCO,5 that purpose does not, of itself, suggest an obviously fair allocation of the component amounts or net amount of the account balances to customers.6
The rates in place in 2000 were implemented to recover forecast costs. Unfortunately, the pool prices in 2000 were much higher than forecast, leading to large balances in the DISCO deferral accounts that are now due to the DISCO. While interim riders to collect these amounts have commenced, the bulk of the DISCO deferral account balances remains to be collected. The Board clearly has the obligation and the authority to determine the appropriate final share of the deferral account balances due from each customer class. The assignment of a share of the balances to any customer class will effectively increase the amounts paid by customers in that class for electric energy purchased in 2000.
The purpose of this Decision is to provide a fair allocation of the net amount in each DISCO’s deferral account to the customer or rate classes of each DISCO. The DISCOs will be allowed to collect the amounts allocated to each rate class from the customers within the rate class. By the very nature of the deferral accounts, the final collection must be effected on an after-the-fact basis – i.e. after the end of the test period. 7
Nevertheless, contrary to the suggestions of some parties, the Board does not consider the allocation and collection of deferral accounts amount to retroactive rate-making since the rates that were approved for the year 2000 were expressly subject to the Board’s determination of the final disposition of the amounts in the deferral accounts. In that respect, the Board said the following in Decision 2001-45:
The Board notes that the tariffs resulting from the 1999/2000 GTA-related Decisions were intended to have effect until December 31, 2000. In that respect, the Board considers the following reference from Decision U99099 to be relevant:
5 In AE’s case, the purpose of the deferral account was to capture the pool price variance from forecast on the volume forecast to be consumed by AE’s customers. This difference is discussed later in this Decision. 6 The Board notes that each DISCO netted GENCO generation and ancillary service, GENCO STS and other reservation price adjustments against its PPDA. The Board considers it more fair and accurate to determine an appropriate allocation of each of these GENCO components to rate class and has done so in Section 5 of this Decision. 7 The Board permitted UNCA to begin collection of its PPDA on an interim refundable basis in Decision 2000-60, dated August 31, 2000. After the Deferral Accounts Regulation was enacted on November 28, 2000, the Board, in Decision 2000-78 dated December 19, 2000, rescinded the PPDA collections scheduled to commence January 1, 2001.
EUB Decision 2002-026 (April 18, 2002) • 3
PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding
For all of the above reasons, the Board agrees with IPCAA that GENCO, TRANSCO and DISCO prices and tariffs should only remain in effect until 31 December 2000. The Board directs AE, EPGI, EPTI and TransAlta, in their refilings, to clearly state that their prices and tariffs are in effect on a final basis only until 31 December 2000. The Board recognizes that there will be further adjustments due to the disposition of deferral accounts. The Board directs AE, EPGI, EPTI and TransAlta to file an application for rates effective 1 January 2001 if such new rates require Board approval.8
Accordingly, the Board concludes that the period in which the tariff was intended to have effect was the years 1999 and 2000, but that the tariff was intended to be subject to adjustments due to the disposition of the deferral accounts upon further review by the Board. …
The Board agrees with IPCCAA that the deferral accounts have not been reconciled and the monies have yet to be disbursed. A decision to review the sharing of the amounts in the deferral accounts and the ultimate collection and disbursements of funds will be prospective in nature.9
The intended purpose of the PPDAs was to account for the difficulty of making reasonable forecasts of energy costs in 1999 and 2000 due to pool price volatility. The theory behind the deferral account mechanism is that, over time, surpluses and deficits should roughly balance out so that neither utility nor customer faces the unfortunate prospect of large amounts to be paid or collected at the end of the tariff period. Regrettably, the circumstances in 2000 were far beyond the expectations of everyone, including the Board. Although the resulting large DISCO PPDA balances will result in the effective price of energy for customers in 2000 being higher than the rates in place in that period, the existence of these balances themselves and their allocation to customers at the end of the test period in no way violates the principle that rates should be established prospectively.
In determining a fair allocation of the deferral account balances, the Board does not consider it necessary to completely redesign the rates that were in place in 2000 and use the redesigned rates as the primary tool to determine rate class allocations. In the Board’s view, the appropriate allocation of the deferral accounts will, instead, culminate in a deficiency rider to be applied to distribution tariffs on a going forward basis10.
8 Decision U99099, page 12 9 Decision 2001-45, page 23 10 The allocated deferral account balances will be recovered prospectively typically by way of a rate class deficiency rider applied to the distribution tariff of customers who were on Option G in 2000. Customers who have become transmission-connected customers with service supplied by the TA, or have become industrial systems, will be billed directly.
4 • EUB Decision 2002-026 (April 18, 2002)
PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding
Notwithstanding these considerations, the Board does consider it appropriate and necessary to take into account the actual circumstances in 2000, including collections from customers through approved rates, in order to determine a fair allocation of the net DISCO deferral account balances to customers.
The task facing the Board in this Decision is to determine a fair methodology for each DISCO to use to allocate to rate classes the approved balances in each of its deferral accounts.
For editorial reasons, the Board has decided not to reproduce the Views of the Parties in Sections 3 and 4 of this Decision. Instead, the interested reader is referred to Appendix 5 and Appendix 6 of this Decision for a complete, detailed description of the Views of the Parties in relation to allocation to customers of the DISCO deferral accounts as submitted by way of evidence and argument in the course of these proceedings. The Board has considered all of this material in arriving at the following findings.
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3 BOARD DETERMINATION OF ALLOCATION METHODOLOGY
3.1 Analytical Framework The record of the PPDA proceeding was complex due to both the circumstances in 2000 and the causes of the components of the deferral account balances. Parties made a particularly wide range of submissions in relation to allocation.
As might be expected, the Board does not necessarily agree with the parties’ views of the facts. More importantly, however, in many cases the Board disagrees with parties’ approach to the applicable regulatory principles. For example, some parties took the position that the economics implicit in the rates designed and approved for 2000 should be maintained. For the reasons set out earlier in this Decision, the Board is of the view that this position is incompatible with the establishment of deferral accounts and fails to recognize that the economics implicit in the rates were expressly subject to change at the time of the disposition of the deferral accounts.
Matters were further complicated by the role of the legislated hedges and the large variation in pool prices in 2000 from the 1998 pool price record, which were used to design the 2000 rates. As a result, the Board has undertaken a detailed analysis of the record of this proceeding and prior Board Decisions. The Board carried out its analysis following these steps:
• Review the formulae used to establish the PPDA • Determine the principles that would lead to a fair PPDA allocation methodology • Determine the customer classes, if any, which should be excluded from the allocation. • Examine the allocation methods proposed by parties to the proceedings to determine the extent to which the proposed methods reflect the principles
EUB Decision 2002-026 (April 18, 2002) • 5
PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding
• Design a principle-based methodology to determine the pool purchase deficiency by rate class • Design a principle-based methodology to determine outstanding UOV refunds11 by rate class • Design a principle based methodology to allocate the net DISCO PPDA deficiency to rate class • Review the implications of the Board’s principle-based allocation methodology • Review the fairness of the Board’s principle-based allocation methodology
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3.2 PPDA Formulae In determining an allocation methodology, the Board considers it important to review the formulae used to establish the PPDA.
The Board notes that the net PPDA balances for AE DISCO and UNCA arise from two slightly different formulae. The UNCA formula arose from a fully litigated process while the AE formula was one of a number of deferral account formulae arising from the Board’s approval of a negotiated settlement.
The formula established for the UNCA deferral accounts comprises the following two components for each hour of the year:
Pool price deferral = Component 1 – Component 2
where the Components are defined as follows:
Component 1 = (Actual pool price – Forecast pool price) x (Actual energy purchases) Component 2 = (Actual DISCO entitlement – Forecast DISCO entitlement)
The formula approved for AE DISCO12 in the 1999/2000 Settlement comprises the following two components:
Pool price deferral = Component 1– Component 2
where the Components are defined as follows:
Component 1 = (Actual pool price – Forecast pool price) x (Forecast energy purchases) Component 2 = (Actual DISCO entitlement – Forecast DISCO entitlement)
UNCA’s deferral account was to capture 100% of the pool price variance at actual volumes. Therefore, for UNCA, the net Component 1 of its PPDA includes UNCA’s actual 2000 pool purchases, including those for Option G and DAT, less the forecast 2000 pool purchases,
11 Note that “entitlements” are sometimes referred to as “UOV refunds” or “UOVs”. 12 See Appendix 3 for a complete list of the AE DISCO deferral accounts.
6 • EUB Decision 2002-026 (April 18, 2002)
PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding including those for Option G and DAT (i.e. the increase in actual DISCO pool purchase costs over forecast).
In contrast, AE DISCO’s PPDA was to capture 100% of the pool price variance at forecast volumes. Therefore, AE DISCO’s net PPDA balance should be the actual 2000 pool purchases normalized to forecast volumes less the forecast 2000 pool purchases.
Similarly, each DISCO’s PPDA should capture 100% of the pool price variance at actual entitlement volumes for the UOV refunds13. Therefore, Component 2 of each DISCO’s PPDA should be the net of actual 2000 UOV refunds less the forecast 2000 UOV refunds - i.e. the increase in actual DISCO UOV refunds over forecast.
The Board notes that both the DISCO pool purchase costs and UOV refunds are costs/benefits that the DISCO faced/received at the DISCO level.
3.3 Principles The first question addressed by the Board is what principles should be used to determine the amounts of the net PPDA that should be fairly allocated to each customer class.
As a matter of general principle, to allocate to customers any cost/benefit incurred/gained at the DISCO level, the Board first looks to cost causation to ensure that customers pay/receive the cost/benefit that they cause the DISCO to incur/gain. Reliance on the principle of cost causation is intended to eliminate cross-subsidization between customer classes and the Board considers it to be the primary principle that should be employed in the allocation of the DISCO deferral accounts.
The Board would normally look to other fairness concerns, such as the relative size of rate increases or other unfair circumstances, only after application of the cost causation principle and the results of that application had been determined. Mitigation of rate increases, for any class, or the alleviation of other unfair circumstances may require a certain amount of cross-subsidization among customers.
In employing cost causation in the present context, the Board notes that the PPDAs include some components that increase and some components that decrease the deferral account balances. The balances in the DISCO PPDAs are the net result of these component increases and decreases.
The Board also notes that, according to UNCA’s Exhibit #314, BR-19, Schedule 8-B Rev 1 (April 24, 2001), the average pool purchase cost for UNCA was $135.34/MWh, (which was 4.75 times the forecast pool price of $28.5214), while the average UOV refund was $105.77/MWh (which was 4 times the forecast UOV refund of $26.5415). Individually, each amount dwarfs the net cost of $29.57/MWh (i.e. $135.34 – 105.77). Furthermore, their relationship to each other changed from the forecast levels included in the 2000 rates: on a forecast basis, the ratio of the
13 Note that “entitlements” are sometimes referred to as “UOV refunds” or “UOVs”. 14 Exhibit 341, Schedule 2.1 15 Shown on Appendix 2 as forecast “Entitlements Component”
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PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding
pool price to entitlements was 1.60, whereas on an actual basis, the ratio of pool price to entitlements was 1.26.
In the Board’s view, the appropriate allocation of the components decreasing the net deferral account is no less important than the appropriate allocation of the components increasing the net deferral account. Therefore, in the Board’s view, appropriate application of the principle of cost causation in the circumstances requires that the PPDA components causing increases and those causing decreases should be dealt with individually, to the extent practical, to ensure that each rate class essentially pays its fair DISCO costs and receives its fair DISCO benefits.
In other words, the allocation methodology must recognize that the pool purchase component (i.e. Component 1 of the PPDA formulae) was increased by higher than forecast pool prices and customer behavior in responding to the higher prices. However, the entitlement component (i.e. Component 2 of the PPDA formulae) also increased due to higher than forecast pool prices and had the effect of decreasing the PPDA balance.
The Board considers that an equitable allocation of the DISCO deferral accounts based on these cost causation principles should result in all customer classes paying the same portion of the net pool purchases that they caused the DISCO to incur on their behalf. In other words, cross- subsidization between customer classes of net pool purchases should be minimized.
In the Board’s view, the primary result of applying a cost causation principle to determine the allocation methodology would be that all classes will essentially be responsible for the full amount of the net pool purchases that they caused the DISCO to incur on their behalf in 2000.
The Board notes a number of fairness concerns raised by customers that should be examined after cost causation is applied to determine if those concerns would require that some customer classes should cross-subsidize other classes, notwithstanding cost causation. Examples of these fairness concerns are as follows:
• Some parties submitted that the rate design used in the last Phase II, including the methodology used to allocate the forecast legislated hedges to customer classes or the rate caps, should be changed as little as possible.
• In the Industrial Power Consumers and Cogenerators Association of Alberta’s (IPCCAA) view, fairness requires that the price signal the Board provided to customers in the rates in place for most of 2000 should be preserved to the extent possible in the after-the-fact allocation of the legislated hedges. IPPCAA suggested the following standard, namely that “fundamental change … should only be undertaken if the Board is convinced that this would have been contemplated by customers at the time the deferral accounts were created.”
• Some parties submitted that actions taken by some customers to reduce their own purchase costs might also have resulted in lower costs to other customers by keeping overall pool prices lower.
8 • EUB Decision 2002-026 (April 18, 2002)
PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding
• Some parties submitted that certain customer classes should be excluded from the allocation.
In Section 4 of this Decision, the Board examines the primary fairness concerns that parties raised regarding the appropriate allocation of the PPDA.
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3.4 Exclusion of Classes from PPDA Allocation The Board considers that one fundamental fairness concern must be addressed prior to determining an appropriate cost-based allocation. That concern is whether any customer classes should be excluded from paying a portion of the net DISCO PPDA balances.16
As the Board has already noted earlier in this Decision, only in the absence of deferral accounts can Board-approved rates determine the final economics for energy purchases by customers. When deferral accounts are established, the economics implicit in the rates must be viewed as interim and subject to the eventual disposition of the deferral accounts. Essentially, the final economics for energy purchased in 2000 will reflect both the price paid for electricity in 2000 through the rates in effect and the allocated portion of the 2000 deferral account balances.
However, the Board notes that the overall charges payable in 2000 by customers served under negotiated rates17 were negotiated based either on pool price flow-through or on actual 2000 pool prices that were in effect at the time of the negotiation and the customers subject to those rates received no portion of the legislated hedges. In effect, the customers served under these negotiated rates have already paid the costs incurred by the DISCO on their behalf and those costs would not have been included in the DISCO PPDA. Therefore, for these customers, the Board considers that it would be inappropriate to affect the overall rate level payable under these negotiated rates in an after-the-fact allocation of the DISCO PPDAs.
16 As noted earlier, UNCA Option G and actual pool price DAT customers are each considered a separate customer class in this Decision. 17 UNCA Rate 6600 Temporary Energy Service, UNCA Rate 6700 Real Time Pricing, and AE Rate Pool Opportunity Rate Price Schedule 33.
EUB Decision 2002-026 (April 18, 2002) • 9
PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding
However, the Board considers these negotiated rate classes to be fundamentally different from DAT (AE DISCO & UNCA DISCO) and Option G (UNCA DISCO only) for the following reasons:
• The negotiated energy charges were based on actual 2000 pool price levels. • The DAT and Option G were each Board approved rates. • The DAT and Option G customers each received an allocation of the legislated hedges and not just actual 2000 pool prices levels. • DAT customers received a monthly DAT Rate Adjustment that was forecast to reduce their 2000 energy charges to the levels of single price fixed rate classes (based on the 1998 pool price record) if they consumed on the class average basis. • Option G customers received a monthly GAC adjustment to their rate levels that was forecast to reduce their 2000 energy charges to the levels of fixed price rate classes (based on the 1998 pool price record) if they consumed on the class average basis.
Therefore, all customers, other than negotiated rate customers, saw rates designed based on the 1998 actual pool price record. Fixed rate customers, including time-of-use (TOU) customers, saw fixed rates for their energy purchases designed on 1998 average price levels for the periods during which their consumption was forecast to occur. DAT and Option G customers saw the 2000 pool price for their energy purchases but adjusted by the DAT Rate Adjustment and the GAC adjustment back towards the average 1998 levels.
While no party suggested that the economics of fixed rate customers should not change in the after-the-fact allocation of the deferral accounts, some parties submitted that the economics of DAT and Option G customers should not change. Representatives of those customers also indicated that DAT and Option G customers made consumption decisions in 2000 based on overall price.
In regard to Option G customers, Alberta Newsprint Company/Millar Western Forest Products Limited (ANC/MW) submitted that it would be fundamentally unjust and unreasonable to effectively change the economics that were in place over the first eight months of 2000 when they have no opportunity to revisit the decisions that were made at that time, but likely would have made different decisions had different economics been in place. IPCCAA noted that the DAT passed through the pool price and a share of UOV refunds and submitted that it was therefore logical to exclude DAT customers from allocation of the pool price and UOV-related deferral account components.
The Board disagrees with ANC/MW and IPCCAA.
The Board observes that fixed rate customers also made their consumption decisions based on the overall economics implicit in their rates during 2000. The Board considers that many of these customers might also have made different consumption decisions if the allocation method and resulting economics had been known in 2000. On the face of it, therefore, it appears to the Board that it is equally fair for DAT and Option G customers to see their economics change, as it is fair for fixed rate customers to see their economics change through a fair after-the-fact allocation of the deferral account balances.
10 • EUB Decision 2002-026 (April 18, 2002)
PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding
Once the deferral accounts were established, without any certainty as to how they would eventually be allocated to customers, there was uncertainty for any customer class as to the final economics for energy purchased in 2000. Furthermore, when the deferral accounts were established, no customer class was excluded from paying/collecting a fair share of the deferral accounts upon their disposition. The allocation of a deferral account, by its very nature (after-the- fact), cannot leave unchanged the economics created by the rates that were in place in 2000 for all customers.
Consequently, for year 2000 consumption, all price signals were effectively interim price signals. The total amounts paid for energy through the 2000 rates were expressly subject to change upon Board consideration of the appropriate disposition of the deferral account balances. In the Board’s view, all DISCO customers should have understood the potential impact of the disposition of the deferral account balances given their nature and purpose.
The Board considers that it would be much less fair for any customer class to be cross-subsidized by other customer classes as a result of the allocation of the deferral accounts than for class economics to change to reflect proper cost causation in 2000.
For the reasons set out above, the Board concludes that only UNCA Rate 6600 Temporary Energy Service, UNCA Rate 6700 Real Time Pricing and AE Rate Pool Opportunity Rate Price Schedule 33 rate classes should be excluded from the allocation of the year 2000 DISCO deferral accounts
Also for these reasons (and the other reasons set out in Section 4 of this Decision dealing with Fairness Considerations), the Board concludes that all other customers should be included in the allocation of the year 2000 DISCO deferral accounts, as necessary, to reflect the fair allocation of each DISCO’s deferral account in accordance with the principles set out in this Decision.
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3.5 Derivation of DISCO UOV Refunds One of the more controversial issues in the proceeding was the appropriate method of allocating UOV refunds. As a result, the Board considers it important to review the derivation of DISCO UOV refunds as background prior to assessing proposed PPDA allocation methodologies.
According to the system of legislated hedges established by the EU Act, for each hour in 2000 when the pool price exceeded a regulated generating unit’s UOP, that regulated generator was required to refund a UOV to the entitled DISCOs equal to the difference between the pool price and the unit’s Board-approved UOP multiplied by its Unit Obligation Amount (UOA) − i.e. (Pool Price – UOP) × UOA.
The sum of all UOVs from all regulated units in each hour was refunded to and shared by the six entitled DISCOs and the TA. The entitlement share of the DISCO determined the portion of the hour’s total UOVs received by the DISCO. These UOV refunds, as they have been termed in prior decisions, were the value of the entitlements due a particular DISCO over a period of time.
EUB Decision 2002-026 (April 18, 2002) • 11
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The allocation of the UOV refunds due in any given hour to DISCOs and the TA was based upon legislated entitlement percentages in each hour.18 The entitlement percentages were derived using the actual hourly load of the DISCOs and the TA for 1994 and their share of the forecast hourly load for the year 1999. These amounts were the end points of a straight-line interpolation used to determine the entitlements for the years in-between.19 The percentage shares for 1999 derived from the interpolation were legislated to apply to the year 2000 as well.20
While the actual year 2000 hourly load profile of each DISCO and the TA may have borne little resemblance to their original year 1999 forecast hourly load profiles, the legislated entitlement share still determined the portion of the UOV refunds that were paid in each hour to each DISCO and the TA in 2000. Therefore, the hourly UOV refunds could be considered to represent a hedge against the hourly pool price (i.e. reduction in cost) for a certain volume of load representing the DISCO’s entitlement share of total UOAs of all regulated generating units (the hedged load).
In other words, the higher the pool price in a given hour, the higher the UOV refunds to which the DISCO was entitled. The entitlements also increased with volume in on-peak consumption periods. Therefore, the amount of the UOV refund in any given hour was fully determined by the pool price in that hour, the fixed legislated amounts, and the Board-approved UOPs. This system maintained the cost to serve the DISCO’s hedged load at a relatively fixed price once the pool price exceeded the highest UOP of the called (i.e. dispatched) generators in the hour.21
In the Board’s view, the key point of the UOV system in the context of the PPDA allocation exercise is that the amount of the hourly UOV refund due to the DISCO was driven by the hourly pool price and the DISCO’s legislated, hourly entitlement profile. In other words, variations in the hourly UOV refunds were directly proportional to variations in the hourly pool price. This point is significant to the Board’s consideration of whether the UOV refunds component of the PPDAs should be allocated on a monthly or hourly basis.
3.6 Assessment of Proposed Methodologies In this section, the Board will review the allocation methodologies proposed by parties to the PPDA proceeding to determine whether the methodologies:
• Follow cost causation principles in the allocation of pool purchase costs and the legislated hedges. • Would result in a fair allocation of deferral account balances among fixed rate classes and actual pool price DAT and Option G customers based on cost causation.
18 See the Entitlement Shares Regulation, AR 223/95, as amended. 19 Decision U97065, page 29 20 EU Act, section 35(3.1) 21 That fixed price was equal to the UOA weighted average of the called generators’ total UOPs. The Board notes that the weighted average UOPs would have been increased due to the effect of the increase in gas-fired generation UOPs at higher gas prices, which would have mitigated, to some extent, the increase in the hourly UOV refunds. In the Board’s view, however, this would be a second order effect, since the UOAs of the gas units were typically significantly smaller than the UOAs of the coal units.
12 • EUB Decision 2002-026 (April 18, 2002)
PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding
AE DISCO and UNCA each proposed a different method to allocate the amounts accumulated in their PPDAs to fixed price customer rate classes.
AE DISCO’s allocation methodology was characterized during the PPDA Proceeding as being a “top-down” approach and was described as follows:
It looks at hourly deferral account accumulations and apportions it to rate class based on fixed price energy use during that hour.22
UNCA’s allocation methodology was characterized as a “bottom-up” approach and was described as follows:
In the allocation, we took more of a bottom-up approach which said, Allocate the total cost incurred by the DISCO in purchasing generation where acquiring generation for customers to rate classes on the same principle as were established in the 1996 Phase II decision. And that is total cost, both costs that were forecast and actual costs that are included in the deferral account above forecast. That is what is in Column A. So, that is total generation cost, not just the deferral cost. And then we took the total revenue received from customers in Column B and said, Well, the difference between those two numbers is really what each rate class would have been allocated had we had a perfect forecast of 2000 and prior to 2000 and done a cost allocation based on that.23
The “bottom-up” approach allocates the total actual pool purchases and actual UOV refunds, whereas the “top-down” approach essentially allocates the differences between actual and forecast pool purchases and UOV refunds. The “bottom-up” approach compares the allocated total costs with “actual” revenue; the difference between revenue and cost is the deferral amount allocated. In its “top-down” approach AE DISCO proposed that the cost shortfall be allocated directly, so that no revenue components are introduced.
UNCA observed that the principal difference between the proposals is the UOV refund allocation method. Bottom-up and top-down methodologies should produce similar cost allocations, provided the cost components of each were allocated on the same basis — hourly, monthly or annually.
In summary, AE DISCO proposed a top-down allocation of the deferral accounts using the two components of their deferral account formula while UNCA proposed a bottom-up allocation that introduced revenue components. The Board notes that in AE DISCO’s view, the difference between the two methods is whether or not the hourly deferral amounts only are allocated using the characteristics of that hour (the AE DISCO approach), or whether the difference between the actual rate class costs and what the rate class actually paid during 2000 is used to allocate the deferral amounts (the UNCA approach). Most parties agreed that there should be a cost-based allocation to customer classes of Component 1 of the DISCO deferral account formulae. The Board also agrees. In any after-the-fact allocation among customers, the Board does not consider
22 AE Argument, page 20. 23 Transcript 4497.
EUB Decision 2002-026 (April 18, 2002) • 13
PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding
that customer classes should reasonably expect to pay less than the pool purchase costs that they caused the DISCO to incur on their behalf.
Allocating Component 1 to customer classes based on 2000 class hourly energy consumption, as proposed by AE DISCO, would account for customer class growth that varied from forecast. However, as explained earlier, the purpose of a cost-based allocation is to minimize cross- subsidization between customer classes. Therefore, the Board considers that a fair, cost-based allocation of Component 1 for the increase in DISCO pool purchase costs over forecast, must minimize any cross-subsidization between classes for the energy purchased by the DISCO from the power pool in 2000 to serve each class. The Board does not agree that a simple, hourly allocation of Component 1 would minimize cross-subsidization of pool purchase costs between classes for the reasons that follow.
The Board agrees with UNCA that the GAC and DAT Rate Adjustments that reduced the pool purchases revenues24 from certain customers were, like fixed rates, not well designed to recover appropriate costs with the very high levels of average pool price that actually occurred in 2000. These adjustments were essentially designed to lower the rates of Option G and DAT customers to 1998 levels if they exhibited class average consumption characteristics.25 As a result, the revenues recovered from Option G and DAT customers may have been more or less than the cost of the pool purchases by the DISCO to serve those customers. If less than the cost of pool purchases were recovered from Option G and DAT customers, other customer classes subject to deferral account treatment would have to pay that difference. On the other hand, if the difference were not subject to deferral account treatment, the DISCO would have to bear the difference.
However, at the customer class level, the Board considers it unfair for any class to cross- subsidize pool purchase costs of another class. Customer classes normally should pay their own cost of pool purchases by the DISCO to serve them.
For this reason, allocating the balance of Component 1 based on 2000 class hourly consumption is, in the Board’s view, inappropriate. An implicit assumption in allocating the balance of Component 1 based on 2000 hourly consumption would be that all classes have, through their rates, paid the same portion of the total pool purchases costs incurred by the DISCO to serve them. However, the Board recognizes that classes have paid different portions of their total pool purchases costs for following two reasons:
• In 2000, certain classes purchased a higher percentage of their load in higher cost periods relative to other classes. • The 2000 rates in place resulted in the DISCO collecting different portions of the actual 2000 DISCO purchase costs from each class.
24 Option G customers paid the pool price less the GAC for each MWh purchased. DAT customers paid the pool price less the DAT Rate Adjustment for each MWh purchased. 25 As Decisions U99034 and U99035 indicated the energy portion of all the rates in effect in 2000 contained a component arising from the allocation of the forecast value of the legislated hedges through the H- factor. Some customers also had their energy charges lowered by the DAT Rate Adjustment and/or GAC. All energy charges/credits were derived or based on rates derived from the 1998 pool price record that was much lower than the 2000 price levels.
14 • EUB Decision 2002-026 (April 18, 2002)
PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding
In the Board’s view, allocating the balance of Component 1 based on 2000 hourly consumption does not account for the second reason and would, therefore, not be appropriate in the circumstances.
GAC (i.e. Option G) and DAT customers highlight the problem of achieving a fair, after-the-fact allocation of the net Components 1 and 2 based on actual hourly class usage. Appendix 4 illustrates that the GAC reduced the energy revenues collected from Option G customers so that the revenues did not fully recover the pool purchase costs incurred by the DISCO on their behalf. This shortfall was most pronounced in August 2000 in which Option G customers received an equivalent net credit of $10.98/MWh for every megawatt hour of energy consumed. Appendix 4 similarly illustrates that the DAT Rate Adjustment reduced the energy revenues collected from DAT customers so that these revenues also did not fully cover the pool purchase costs incurred by the DISCO on their behalf.
However, the 2000 rates in place for other customer classes also resulted in the DISCO collecting different portions of its actual 2000 DISCO purchase costs for each class resulting in revenues that did not fully cover the pool purchase costs incurred by the DISCO. The Board notes that the deficiencies incurred by the DISCO for each rate class with respect to Component 1, including Option G and DAT customers, is offset by the UOV refunds received by the DISCO in Component 2.
The principle that cross-subsidization between customer classes should be minimized through a fair, cost causation-based allocation of the deferral account requires a comparison of the costs of the pool purchases the DISCO incurred on behalf of each customer class to the revenues the DISCO has received from the class. Therefore, the Board considers that in a fair, after-the-fact allocation of Component 1, the DISCO’s pool purchase collections shortfall, the Board must consider the share of each class’s actual 2000 energy purchase costs that was paid by customers through the rates in place in 2000.
In the Board’s view, UNCA’s fixed rate customer classes would have to subsidize the net collection shortfall of DAT and Option G customers if DAT and Option G classes were not each allocated a part of the net deferral account based on their respective pool purchase collections shortfall.
In AE DISCO’s case, there were no Option G customers. In addition, AE DISCO’s deferral account only increased with the pool price rather than with the consumption of certain customer classes. However, the Board considers that using the same allocation methods used for UNCA will lead to a fairer allocation of AE DISCO’s net deferral account to customers than an allocation based only on hourly class consumption.
In the Board’s view, the principle that all classes should pay the same portion of the 2000 pool purchases they caused the DISCO to incur on their behalf, suggests a parallel principle that would apply equally to AE DISCO’s customer classes. In an after-the-fact allocation based on cost causation, it would be unfair for customer classes that have already paid for their forecast
EUB Decision 2002-026 (April 18, 2002) • 15
PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding
pool purchases26 through their rates to be subject to as high or higher portions of the DISCO pool purchases deferral than customer classes that have paid less of their forecast pool purchases.
Similarly, for both AE and UNCA, a fair allocation of Component 2 to customer classes must consider the value of the UOV refunds which classes have already received, through their rates, based on their actual consumption.
In the Board’s view, although some aspects of each of the methods proposed by AE DISCO and UNCA DISCO do have merit, taken as a whole, neither of the proposed methods complies with the cost causation principles established earlier in this Decision. Therefore, the Board is not persuaded that either the top-down allocation as proposed by AE or the bottom-up allocation proposed by UNCA would result in a fair allocation to all customers of the net amount owed the DISCO.
In the next section, the Board sets out its views on an appropriate methodology that will result in a fair allocation to customers of the net PPDA balances of AE and UNCA DISCOs having regard to the cost causation principles established by the Board.
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3.7 Board Determination of a Cost-Based Allocation Methodology Having regard to the considerations expressed in assessing the methodologies proposed by AE and UNCA, the Board has concluded that a top-down allocation methodology introducing actual revenue components would result in the determination of an appropriate cost-based allocator of the net PPDA balances and would achieve a fair, cost-based allocation to customer classes.
In the Board’s view, the methodology first requires the determination of the appropriate class pool purchase deficiency and the outstanding UOV refunds due each customer class. The class pool purchase deficiency and the outstanding UOV refunds due each customer class can then be netted to determine a preliminary shortfall for each customer class. The preliminary shortfall can then be used as a cost-based allocator27 to allocate the PPDA to each customer class as set out in Appendix 2 (UNCA PPDA Allocation Sheet 1 and AE PPDA Allocation Sheet 3).
3.7.1 Rate Class Pool Purchase Deficiency 3.7.1.1 Board Template The Board has prepared a template (see Appendix 2) that illustrates the Board determined cost- based method of allocating the 2000 net DISCO Deferral Account deficiency (Allocation Template). The Board considers these deficiencies to be essentially net DISCO collection shortfalls relating to increases in pool price over the forecasts on which the 1999/2000 tariffs were based. These net collection shortfalls arose because customer rates were insufficient to recover the total pool purchase costs incurred by the DISCO on the customers’ behalf.
26 Forecast class consumption multiplied by actual pool price. 27 The percentage share of the PPDA balance allocated to each rate class is simply the ratio of the preliminary shortfall for that rate class divided by the sum of the preliminary shortfalls of all rate classes.
16 • EUB Decision 2002-026 (April 18, 2002)
PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding
Slightly restated from earlier, the pool purchases deficiency component of each PPDA Component 1 is as follows:
• UNCA Component 1 = (Actual pool price × Actual energy purchases) – (Forecast pool price × Actual energy purchases)
• AE Component 1 = (Actual pool price × Forecast energy purchases) – (Forecast pool price × Forecast energy purchases)
For UNCA Component 1 traces the effects of both higher pool price and higher consumption because it is based on actual energy purchases on behalf of each customer class. Because AE DISCO bears the risk of volume variance according to its PPDA formula, this element of Component 1 traces only the effect of higher pool price since it is based on forecast energy purchases of each customer class not actual consumption.28 In both cases, however, the relevant volume (forecast or actual) of energy per customer class in each hour, multiplied by actual pool price in that hour, derives the portion of DISCO pool purchase costs attributable to, or caused by, that customer class.
3.7.1.2 “Actual” Class Pool Purchase Costs Accordingly, the first element of Component 1, Actual pool price times energy purchases (actual UNCA or forecast AE) can be traced down to the customer class level. Higher pool purchase costs for each customer class as a result of actual pool prices exceeding forecast pool prices can easily be determined for each class.
Applying the cost causation principle, the volume of energy purchased by UNCA on behalf of each rate class in each hour multiplied by the actual pool price in that hour represents the portion of the UNCA pool purchase costs caused by the rate class. Similarly for AE, since it bears the volume risk, the volume of energy forecast to be purchased by AE on behalf of each rate class in each hour multiplied by the actual pool price in that hour represents the portion of the AE pool purchase costs caused by the rate class.
Accordingly, Column B of Appendix 2 illustrates how the “actual” 2000 pool purchase costs incurred by the DISCO to serve each customer class are determined.29
For example, for UNCA’s Residential class (Appendix 2, page 1 of 4), 2026 GWh of energy were actually purchased in year 2000 (Column A) at a total, actual cost of $294.827 million (Column B). In contrast, for AE DISCO’s Residential class (Appendix 2, page 3 of 4), 795 GWh of energy was forecast to be consumed by the class in year 2000 (Column A) and, at actual hourly pool prices, cost a total of $117.737 million30 for AE DISCO to purchase. The actual cost of any variance from this forecast consumption is effectively borne by AE DISCO.
28 Actual consumption by each of AE DISCO’s customer classes is not necessarily immaterial to the pool purchase deficiency since increased consumption may have placed upward pressure on pool price in any given hour. Any such effects can be neither determined nor accounted for in the allocation exercise. 29 Appendix 2 (page 1 of 4), relates to UNCA DISCO; Appendix 2 (page 3 of 4) relates to AE DISCO. 30 The Board has used illustrative numbers only in AE DISCO Col B Appendix 2(page 3 of 4)
EUB Decision 2002-026 (April 18, 2002) • 17
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Again, to emphasize for clarity, the Board uses the phrase “actual” pool purchase costs to be defined as actual costs for actual energy purchased for each UNCA DISCO customer class and the cost of forecast energy deemed to be purchased at the actual pool prices for each AE DISCO customer class.
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3.7.1.3 “Actual” Class Pool Purchase Revenues The second element of Component 1, Forecast pool price times energy purchases (actual UNDA or forecast AE), can similarly be traced to the customer class level according to the principle that 2000 rates were set to recover forecast costs at the forecast pool price level for each class. In other words, a portion of the DISCO pool purchase costs caused by each rate class has already been collected from each class through the energy portion of their rate. Consistent with the cost causation principle, a shortfall can be determined by rate class by subtracting the revenues collected from the class from the costs caused by the class. Therefore, for allocation purposes, this second element of Component 1 is best determined for each class by calculating the “actual” revenues collected by rate class.
Calculating what the DISCO paid for pool purchases for each customer class is relatively simple. However, calculating the amounts the DISCO collected for pool purchases from each class is more complex. The Board considers that each 2000 charge collected from customers or each 2000 credit paid to customers that affected the amounts paid by customers for the energy they purchased (or, for AE were, forecast to be purchased) must be considered individually to determine how it should be treated in the calculation.
The energy portion of most base rates, with the exception of those for demand-only customers,31 was the average forecast pool purchase cost (based on the 1998 pool prices record) less the H- factor. The H-factor was the forecast value of the net legislated hedges − i.e. the Reservation Price (RP) less UOV refunds per MWh of forecast DISCO purchases. GAC and DAT Rate Adjustments reduced the energy charge from pool price for the customers receiving those adjustments. All of the base rates were also affected by a number of riders in 2000.
The Board has determined that class pool purchase revenues need to be adjusted by the following significant revenue/credit elements:
H-factor Credit The Board considers that the effects of the legislated hedges embodied in the H-factor and riders affecting the H-factor should be removed since they were amounts unrelated to the recovery from customers of purchases from the Power Pool.
GAC/DAT Credits Similarly, the Board considers that the GAC and DAT Rate Adjustments, and riders affecting them, had the effect of reducing the per unit energy cost recovery for pool
31 I.e. Streetlight and oilfield energy only classes
18 • EUB Decision 2002-026 (April 18, 2002)
PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding
purchases from customers eligible for them in 2000 and, therefore, reduced the collections from eligible customers for pool purchases to an amount lower than the pool price.
STS Charges The energy revenues for rate classes other than 6300/6400 and Option G/DAT were increased to reflect the higher forecast pool price charges as a result of the implementation of STS charges effective Jun 1, 2000. The energy rates for rate classes 6300/6400 and Option G/DAT were adjusted, in Decision 2000-31, to reflect the higher forecast pool price charges as a result of the implementation of STS charges effective June 1, 2000.
In all three of these cases, the credits or charges effectively adjusted the collections by the DISCO from each customer class to reflect the “actual” net revenue received by the DISCO towards the recovery of “actual” pool purchase costs on behalf of the customer class.
Accordingly, Column G (UNCA DISCO) and Column F (AE DISCO) of Appendix 2 illustrate how the “actual” 2000 pool purchase revenues collected by the DISCO should be determined by customer class.
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3.7.1.4 Method of Determining Pool Purchase Deficiency Having regard to the foregoing, the Board considers that the method set out below to determine the customer class-specific collection shortfalls will ensure that each class will essentially be responsible for the “actual” cost pool purchases by the DISCO to serve that class. In the Board’s view, this method reflects proper cost causation principles by minimizing cross-subsidization of customer class pool purchase costs.
Accordingly, the Board directs UNCA DISCO to use the Board’s Allocation Template in Appendix 2 and to follow the steps explained below to determine the “actual” pool purchase shortfall for each customer class:
Step 1: Calculate DISCO hourly “actual” pool purchases by customer class using actual hourly volumes by customer class and actual pool price (this step recognizes the “actual” pool purchase costs caused by each customer class as a whole) as described in the “Actual” Class Pool Purchase Costs section earlier in this Decision.
Step 2: Determine “actual” pool purchase costs already paid by each customer class through existing rates (this step recognizes the “actual” revenues − i.e. energy charges absent the allocated H-factor and other adjustments−received by the DISCO towards those pool purchase costs) as described in the “Actual” Class Pool Purchase Revenues section earlier in this Decision.
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Step 3: Determine the “actual” pool purchase deficiency for each customer class by subtracting the “Actual” Class Pool Purchase Revenues from the “Actual” Class Pool Purchase Costs.
Also, the Board directs UNCA DISCO to provide two versions of the first page of the Allocation Template as follows:
• Version 1 should allocate the annual deferral account balance per the Template using the characteristics of the entire year 2000 to determine the amounts allocated to each customer class to be used in the determination of the class riders.
• Version 2 should allocate the portion of the deferral account that accrued from January 2000 through August 2000 separately from the portion of the deferral account that accrued from September 2000 through December 2000 using the characteristics of the respective periods. Version 2 should then total the amounts allocated to each customer class over each of the two periods to be used in the determination of the class riders.
If there are any differences in the final amounts allocated to customer class between Version 1 and Version 2, the Board directs UNCA to explain the differences and provide UNCA’s view as to which version produces more equitable results.
Similarly, the Board directs AE DISCO to use the Board’s Allocation Template in Appendix 2 and to follow the steps explained below to determine the “actual” pool purchase shortfall for each customer class:
Step 1: Calculate hourly forecast pool purchases by customer class using forecast hourly volumes by customer class and actual pool price (this step recognizes the “actual” pool purchase costs caused by each customer class in relation to its forecast consumption) as described in the “actual” Class Pool Purchase Costs section earlier in this Decision.
Step 2: Determine forecast pool purchase costs already paid by each customer class through existing rates (this step recognizes the revenues−i.e. energy charges absent the allocated H-factor and other adjustments−forecast to be received by the DISCO towards those forecast pool purchase costs) as described in the “Actual” Class Pool Purchase Revenues section earlier in this Decision.
Step 3: Determine the forecast pool purchase deficiency based on forecast energy use for each customer class by subtracting the “Actual” Class Pool Purchase Revenues from the “Actual” Class Pool Purchase Costs.
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20 • EUB Decision 2002-026 (April 18, 2002)
PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding
3.7.2 UOV Refunds By Rate Class The UOV refund component of the PPDAs for both UNCA and AE DISCO (Component 2) is as follows:
Component 2 = (Actual DISCO UOV Refund – Forecast DISCO UOV Refund)32
In the absence of UOV refunds, according to the Board’s pool purchase deficiency approach, each customer class would face much higher payments towards the pool purchases cost than the DISCO incurred on behalf of that class. However, given that UOV refunds will reduce the amount of the net DISCO Deferral Account balance to be charged to each class, the Board must determine the basis on which the actual 2000 UOV refunds should be fairly allocated to customer classes, considering the hourly method used in the calculation of the pool purchases collection shortfall.
3.7.2.1 Actual Class UOV Refunds Parties proposed allocation of the 2000 DISCO UOV refunds either monthly on the basis of customer class share of monthly DISCO energy volumes, or hourly on the basis of customer class share of hourly DISCO energy volumes.
Arguments in support of the monthly allocation of UOV refunds included the following:
• Some parties submitted that the rate design used in the last Phase II, including the methodology used to allocate the forecast legislated hedges to customer classes or the rate caps, should be changed as little as possible.
• Some parties submitted that actions taken by some customers to reduce the purchase costs that they caused the DISCO to incur on their behalf, may also have resulted in lower costs to other customers by keeping overall pool prices lower and it would therefore be unfair to lessen their UOV refunds by way of an hourly allocation.
Arguments in support of hourly allocations of UOV refunds were as follows:
• Some parties considered that the actual 2000 hourly variation in pool price was much larger than that forecast for 2000 using the 1998 pool price record and hourly allocation was the best way to minimize the effects of the hourly variation.
The Board considers the first element of Component 2, actual UOV refunds for each class, to be readily traceable on a cost basis down to the customer class level for the reasons that follow.
In the Board’s view, while the marginal price signal seen by the DISCOs in 2000 was the pool price, the cost to serve the DISCO’s total load in any hour was not the product of pool price and total hourly load. Instead, that cost in each hour was reduced by the UOV refunds received by the DISCO in that same hour. Effectively, therefore, the actual hourly unit price paid by the DISCO was the pool purchase cost less UOV refunds divided by the DISCO’s load in that hour.
32 Note that the terms “UOV Refunds” and ”Entitlements” are interchangeable
EUB Decision 2002-026 (April 18, 2002) • 21
PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding
Since DISCO pool purchase costs were reduced by the benefits of these entitlements received by the DISCO in each hour, the entitlements effectively reduced the unit price of the DISCO’s pool purchase costs in each hour. Therefore, the hourly entitlements received by the DISCO reduced the hourly pool purchase costs incurred by the DISCO on behalf of each rate class. Viewed accordingly, the entitlements follow the same clear, cost-based trail down to the customer class level as do the DISCO pool purchase costs.
Therefore, a top-down allocation methodology with the introduction of “actual” collected revenue to determine the pool purchases deficiency and the outstanding UOV refunds due each customer class would allow for a fair cost-based allocation of the net of Component 1 and Component 2 to customer classes. The class pool purchase deficiency and the outstanding UOV refunds due each customer class can then be netted to determine a preliminary shortfall for each customer class. The preliminary shortfall can then be used as a cost-based allocator to allocate the PPDA to each customer class as set out in Appendix 2.
Accordingly, the following cost causation principles are reflected in the methodology to allocate to customer classes the net PPDA balance consisting of Component 1 (related to pool purchase costs) and Component 2 (related to UOV refunds):
• DISCO pool purchase costs were caused by the volume of energy purchased by the DISCO in each hour multiplied by the actual pool price in that hour. Therefore, the volume of energy purchased by the DISCO on behalf of each customer class in each hour multiplied by the actual pool price in that hour should be calculated for each customer class to properly recognize the portion of the DISCO pool purchase costs caused by the customer class.
• Hourly DISCO pool purchase costs were effectively reduced by the benefits of the UOV refunds received by the DISCO in each hour. Therefore, the hourly UOV refunds received by the DISCO should be allocated to each customer class for each hour in proportion to the class’s share of the DISCO’s hourly load so that the effective, net unit price paid by the DISCO for pool purchases in each hour is reflected in the volumes purchased on behalf of the customer class in that hour.
In the Board’s view, this approach provides a fair, cost-based allocation of the actual benefits of the legislated hedges to existing and new customers as required by the EU Act given the implementation of deferral accounts for year 2000.
The Board notes that, in the rate design, forecast UOVs were allocated to customer class on an annual energy–use (i.e. consumption) basis so as to provide proper price signals for DAT and Option G customers. However, as already noted, the implementation and allocation of deferral accounts effectively modifies the overall economics implicit in the rates that DAT and Option G customers paid during the year 2000. In this after-the-fact allocation, the DISCO’s actual UOV refunds are given to customer classes based on their hourly load in order to properly reflect the net unit price paid by the DISCO for the energy consumed by the class in each hour. Clearly, such an allocation cannot provide meaningful price signals for the year 2000. However, it does change the final economics that customers will see for their 2000 energy purchases. Therefore, in
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PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding
the Board’s view, the issue in this after-the-fact allocation is no longer a price signal issue, but a fairness issue. In appears fair to the Board that each customer class should pay essentially the same net unit price incurred by the DISCO for the energy purchased in each hour on behalf of that class.33
The Board considers this cost causation approach to be fair considering the establishment of the PPDAs. Customers had no way of knowing the ultimate economics of their hourly consumption decisions until the Board’s determinations were set out in this Decision. In these circumstances, particularly given the high variation in pool price from hour to hour in 2000, it would be inappropriate for the Board to pass through to customers the entire hourly variation in the pool purchase price seen by the DISCO and at the same time pass through the UOV refunds on a monthly or annual basis, thereby muting the hourly variation in the UOV refund seen by the DISCO. Instead, in the after-the-fact allocation of the UOV refunds, the Board considers that the hourly variation in pool price should be muted to the extent possible by allocating the UOV refunds on an hourly basis.34
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3.7.2.2 Actual UOV Refunds Received by Classes The second element of Component 2, actual UOV refunds received, can also be traced to the customer class level according to the principle that rates were set to refund forecast UOV refund costs at the forecast pool price level. The entitlement portion of the H-Factor represents the rate at which actual UOVs have already been refunded to rate class through the rates. Therefore, this second element is best determined by calculating the actual UOV refunds received by each customer class.
Column M (UNCA DISCO Appendix 2, page 1 of 4) and Column J (AE DISCO Appendix 2, page 3 of 4) of Appendix 2 illustrates the derivation of the portion of the actual DISCO 2000 UOVs that have already been refunded to customer classes through rates. For UNCA, the Board has used an entitlement rate of $26.54/MWh, which is the entitlement portion of the published H-factor rate of negative $6.70/MWh.
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3.7.2.3 Method of Determining Outstanding UOV Refunds Due to Classes Having regard to the foregoing, the Board considers that the method set out below to determine the outstanding deferral account UOV refunds by customer class will ensure that each class receives its cost-based share of the actual 2000 UOV refunds. In the Board’s view, this method of determining the remaining UOV refunds due to each class, when combined with the method
33 As previously discussed, this method of calculating the pool purchases shortfall reflects the actual consumption decisions made by customers since the amounts calculated are based on the actual load (forecast load for AE) and the actual purchase costs (actual costs of forecast load for AE) incurred by the DISCO on behalf of those customers. 34 Further discussion of fairness concerns in relation to the hourly allocation of UOV refunds are more fully discussed below in Section 4.[Assessment of Board Determined Cost-Based Methodology].
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of determining the class’s pool purchase costs shortfall, reflects proper cost causation principles by minimizing cross-subsidization of net DISCO pool purchase costs.
Accordingly, the Board directs UNCA and AE to use the Board’s Allocation Template (Appendix 2) and to follow the steps explained below to determine the actual outstanding UOV refund due to each customer class:
Step 1: Allocate actual UOV refunds to customer class using actual hourly volumes by customer class (this step reduces the hourly unit price of the customer class’s pool purchases to the same net unit price paid by the DISCO).
Step 2: Determine actual UOV refunds already received by customer class through the UOV refund (entitlement) portion of the H-factor (this step recognizes the credits already paid by the DISCO to customers through the rates).
Step 3: Determine the outstanding UOV refunds due to each customer class.
The Board notes that this approach results in AE’s customer classes paying more or less than the net amount of the DISCO’s pool purchases on their behalf depending on actual consumption, since the actual class loads varied from the forecast class loads used in the deferral account. However, AE’s classes with greater than forecast consumption will appropriately see a greater portion of the UOV refunds while AE’s classes with lower than forecast consumption will see a lower portion of the UOV refunds. In the Board’s view, this approach, on an actual basis, provides a fair cost-based allocation of the benefits of the legislated hedges to existing and new customers as required by the EU Act given the approved structure of AE’s deferral account.
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3.7.3 Allocation of Net PPDA Deficiency In this section of the Decision, the Board will provide directions to AE DISCO and UNCA DISCO with respect to the cost-based allocation of their net PPDA deficiencies.
The Board directs UNCA DISCO to follow the steps explained below to allocate UNCA’s net PPDA deficiency (i.e. the difference between Component 1 and Component 2):
Step 1: Determine the preliminary customer class deficiency by calculating the difference between the amount of the “actual” pool purchase shortfall (i.e. Component 1) and the actual outstanding UOV refunds (i.e. Component 2) for each customer class.
Step 2: Determine the final customer class deficiency by allocating the final, cost-based (i.e. actual) net DISCO PPDA deficiency to each customer class in accordance with that class’s share of the total of all the preliminary customer class deficiencies.
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The Board directs AE DISCO to follow the steps explained below to allocate AE’s net DISCO PPDA deficiency (i.e. the difference between Component 1 and Component 2):
Step 1: Determine the preliminary customer class deficiency by calculating the difference between the amount of the forecast pool purchase shortfall (i.e. Component 1) and the actual outstanding UOV refunds (i.e. Component 2) for each customer class.
Step 2: Determine the final customer class deficiency by allocating the final, cost-based (i.e actual) net DISCO PPDA deficiency to each customer class in accordance with that class’s share of the total of all the preliminary customer class deficiencies.
As a result of this allocation method, customer classes will receive essentially the same $/MWh portion of the total DISCO benefit of purchasing energy for the class in lower pool price hours and pay essentially the same $/MWh portion of the total DISCO cost of purchasing energy for the class in higher pool price hours. Accordingly, each customer class will essentially be responsible for the actual hourly pool price paid by the DISCO to purchase electricity to serve the class, less the UOV refund received by the DISCO in the hour the purchases were made. 35 Overall, therefore, the Board considers this approach to achieve a fair allocation of both pool purchase costs and UOV refunds by minimizing cross-subsidization between classes in respect of net DISCO pool purchases.
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4 ASSESSMENT OF BOARD DETERMINED COST-BASED METHODOLOGY
4.1 Introduction In the previous section, the Board determined a cost-based allocation methodology by which the DISCOs can determine the amounts to be fairly collected from their customers over the collection periods approved by the Board in Decision 2001-92 in respect of their outstanding PPDA balances.
In accordance with the analytical framework and principles established earlier in this Decision, in this section, the Board will assess the determined methodology from the following perspectives:
• General fairness considerations • Option G fairness considerations • DAT fairness considerations • Fairness of the Allocation of the DAT and Option G Adjustment to UNCA PPDA
35 Customers with demands >2 MW will see a direct allocation of the portion of the net deferral account (both benefits and costs) that they must pay as set out in Decision 2002-024.
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In this assessment, the Board will determine whether any adjustments to the cost-based allocation methodology are warranted on fairness grounds prior to finally approving an appropriate allocation methodology for the PPDAs.
4.2 Fairness Considerations (General) The Board will examine general fairness considerations from the following perspectives:
• Review total final 2000 charges to customers classes • Review of existing rate design for the year 2000 • Maintaining 2000 price signals and Customer Class relationships • Fairness within customer classes • Use of 2000 Rate Design Principles • Impact, if any, of Demand side response on UOV Allocation.
4.2.1 Total Final 2000 Economics and Energy Unit Costs The allocation of the PPDA balance will, on an after-the-fact basis, alter the effective 2000 economics for any customer/customer class that is allocated a portion of the DISCO PPDA balances. In other words, the net PPDA charges must be added to the charges the customer experienced in 2000 in order to arrive at that customer’s total final economics related to 2000 pool purchases. Total final 2000 economics can also be viewed in terms of final 2000 energy unit costs. Final 2000 energy unit costs can be calculated by dividing the customer class final 2000 energy costs by the customer class energy purchased in 2000 by the DISCO on behalf of the customer class.
Customers who continue to take distribution service will be affected since the allocated amounts will be collected through the applicable distribution tariff. Customers who have become either industrial systems or transmission-connected customers with service supplied by the TA, will be billed directly in the absence of an applicable distribution tariff for these customers. In the Board’s view, the primary result of applying a cost causation principle to determine the allocation methodology is that all classes will essentially be responsible for the full amount of the net pool purchases that they caused the DISCO to incur on their behalf in 2000.
Application of the cost-based of the allocation method determined in this Decision, would result in all customer classes, including DAT and Option G, seeing either lower unit charges relating to Component 1 of the Deferral Account if they purchased energy in lower pool price periods or higher unit charges if they purchased energy in higher pool price periods. The allocation of the Component 2 UOV refunds on an hourly basis would, for all classes, somewhat mute the net cost of energy purchased in lower and higher pool price periods. All classes would, however, be treated in a consistent manner.
In order to determine the total final economics of each individual Option G and DAT customer, the net PPDA charges (i.e. the net of Component 1 charges and Component 2 benefits) for each such customer must be added to the charges the customer saw in 2000 through the rates if the allocation is approved. Typically, considering the final total charges, Option G and DAT customers who purchased energy in periods of relatively lower pool costs will effectively see
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PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding lower overall 2000 final unit costs than the final unit costs of fixed rate class customers. Conversely, Option G and DAT customers who purchased energy in periods of relatively higher pool costs will effectively see higher overall 2000 final unit costs than the final unit costs of fixed rate class customers. This result is consistent with the purpose of DAT and Option G rates, which was to allow those customers to take advantage of their ability to respond to the variation in hourly pool price and so realize savings relative to fixed rate customers.
The Board also notes that some DAT or Option G customers were only served under their respective rates for a portion of the year. DAT or Option G customers served under these rates for only a portion of the year and who effectively responded to the pool price, will have paid total energy charges that are discounted from the amounts accumulating to fixed rate customers over that portion of the year.
The Board considers that this outcome would be fair on the face of it, however, the Board believes that it is also necessary to consider other significant fairness arguments made during the proceeding to determine if adjustments to the allocation methodologies should be made for certain customer classes.
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4.2.2 Review of Rate Design for 2000 In order to give parties a better understanding of the Board’s rationale for determining the appropriate allocation method for the “actual” pool purchases and UOV refund components of the DISCO PPDAs in this Decision, the Board considers that it is useful to review past Decisions, outlining the framework for the rates that took effect on March 1, 2000 and were therefore in place for most of 2000 (2000 rates). It was during this period that the bulk, about 95%, of the net DISCO PPDA balances accumulated.
In Decisions U99034 and U99035, in which the 2000 rates were designed, the Board indicated that: 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).36 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.37 …
36 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. 37 Decision U99034, page 9; Decision U99035, page 12
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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 maximum incentives for efficient behaviour 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 1996.38 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. 39 … 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.40 … Section 4 of the Distribution Regulation requires that the DAT have a fair and reasonable charge for RPs 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.41
In Decisions U99034 and U99035, the Board took into account all of these considerations, and other factors, when it allocated the legislated hedges through the rate design established in those Decisions. The allocation method was set to provide appropriate price signals to customers on a forecast basis considering the price levels seen in 1998. The rates in place for most of 2000 were also designed, on a forecast basis, to fairly balance the allocation of legislated hedges as between customers on rates that saw the actual hourly variation in pool price (e.g. DAT and Option G) and those customers on fixed rates.
All customers, other than negotiated rate customers, saw rates designed based on the 1998 actual pool price record. Fixed rate customers, including time-of-use (TOU) customers, saw fixed rates for their energy purchases based on 1998 average price levels for the periods in which their consumption was forecast to occur. Option G and DAT customers saw the 2000 pool price for
38 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,…” 39 Decision U99034, page 22; Decision U99035, page 17 40 Decision U99034, page 25; Decision U99035, page 20 41 Decision U99034, page 107; Decision U99035, page 88
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PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding
their energy purchases as adjusted by the H-factor and either the GAC adjustment or the DAT Rate Adjustment towards average 1998 levels.
There were two types of fixed energy price rate classes in 2000:
• the single-price fixed price rate classes; and • the time-of-use (TOU) rate classes that had a number of fixed rates depending upon the time the energy was consumed.
In this Decision as in past Decisions, the Board refers to these fixed energy price rate classes as “fixed price rate” classes or “fixed rate” classes. While the Board has referred to TOU rate classes as TOU direct access tariff (DAT) classes in prior Decisions,42 in this Decision the Board refers to TOU DAT classes as “TOU” classes except when quoting or discussing those prior Decisions. Similarly while the Board has referred to actual pool price DAT classes in prior Decisions,43 in this Decision the Board will refer to actual pool price DAT classes as “DAT” classes except when quoting or discussing those prior Decisions.
The Board considers the following to represent UNCA customer classes exposed to variation in the actual 2000 hourly pool price signal adjusted by the GAC or the DAT Rate Adjustment:
DAT and OPTION G SERVICE customer classes • Rate 6800 Direct Access Tariff (2000 pool price less DAT Rate Adjustment) • Option G Planned Interruption Transition Alternative (2000 pool price less GAC)
The Board considers the following to represent AE rate classes exposed to variation in the actual 2000 hourly pool price signal adjusted by the DAT Rate Adjustment:
DAT SERVICE customer class • Generator Interconnection and Standby Power Price Schedule 32D44 • Short Term Energy Price Schedule 3845 • Direct Access Tariff Large General Service/Industrial – Distribution Connected Price Schedule 39D Direct Access Tariff Large General Service/Industrial – Transmission Connected Price Schedule 39T • Direct Access Tariff – Oilfield Price Schedule 49
The Board considers the following to represent the fixed price rate classes for AE:46
42 Previously referred to as time-of-use DAT in prior Board Decisions 2000-34, 2000-35 and 2000-11 43 Previously referred to as actual pool price DAT in prior Board Decisions 2000-34, 2000-35 and 2000-11. 44 Since the energy charges under AE’s Generator Interconnection and Standby Power Price Schedule 32D are the same as under AE’s DAT, the Board’s findings in regard to the DAT will also apply to 32D. 45 Since the energy charges under AE’s Short Term Energy Price Schedule 38 are the same as under AE’s DAT, the Board’s findings in regard to the DAT will also apply to 32D and 38. 46 A fixed price TOU option (previously referred to as TOU DAT) was also offered for the classes indicated.
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RESIDENTIAL SERVICE customer class • Standard Residential Service Price Schedule 11
SMALL GENERAL SERVICE customer class • Standard Small General Service Price Schedule 21 • Small General Service – Energy Only Price Schedule 22 • Irrigation Pumping Service Price Schedule 25 • REA Irrigation Pumping Service Price Schedule 26
LARGE GENERAL SERVICE/INDUSTRIAL customer class • Energy Price Options – Gas Compression Price Schedule 31A (TOU) • Large General Service/Industrial – Distribution Connected Price Schedule 31D (TOU) • Large General Service/Industrial – Transmission Connected Price Schedule 31T (TOU) • Rainbow Processing Plant Price Schedule 36 (TOU)
OILFIELD customer class • Small Oilfield and Pumping Power Price Schedule 41 (TOU)
FARM SERVICE customer class • REA Farm Service Price Schedule 51 • Farm Service Price Schedule 56
STREET LIGHTING SERVICE customer class • Street Lighting Service Price Schedule 61
PRIVATE LIGHTING SERVICE customer class • Private Lighting Service Price Schedule 63
The Board considers the following to represent the fixed price rate classes for UNCA:
RESIDENTIAL CUSTOMER CLASS • Rate 1100 Residential Service • Rate 1200 Residential Time-of-Use Service
FARM CUSTOMER CLASS • Rate 2100 UNCA Farm Service • Rate 2200 UNCA Farm Time-of-Use Service • Rate 2300 UNCA Grain Drying Service • Rate 2400 REA Farm Service • Rate 2500 REA Farm Time-of-Use Service • Rate 2520 REA Large Farm Service • Rate 2600 UNCA Irrigation Service • Rate 2700 UNCA Irrigation Time-of-Use Service
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• Rate 2800 REA Irrigation Service (Closed) • Rate 2810 REA Irrigation Service • Rate 2900 REA Irrigation Time-of-Use Service
EXTERIOR LIGHTING CUSTOMER CLASS • Rate 3100 Street Lighting Service (Investment Option) • Rate 3300 Street Lighting Service (No Investment Option) • Rate 3700 Festive Lighting Service • Rate 3800 Yard Lighting Service
COMMERCIAL CUSTOMER CLASS • Rate 4100 Small General Service • Rate 4200 Small General Time-of-Use Service • Rate 4300 Small General Temporary Service • Rate 4400 Oil and Gas (Capacity) Service • Rate 4500 Oil and Gas (Energy) Service • Rate 4600 Oil and Gas Time-Of-Use Service
GENERAL SERVICE CUSTOMER CLASS • Rate 6100 General Service • Rate 6200 General Time-of-Use Service • Rate 6300 Large General Time-of-Use Service • Rate 6400 Transmission Service
WHOLESALE SERVICE CUSTOMER CLASS • Rate 8100 Wholesale Time-of-Use Service (Closed)
The overall charges payable in 2000 by customers served under negotiated rates (UNCA Rate 6600 Temporary Energy Service, UNCA Rate 6700 Real Time Pricing and AE Rate Pool Opportunity Rate Price Schedule 33) were negotiated based either on pool price flow-through or on actual 2000 pool prices that were in effect at the time of the of negotiation. Customers subject to these negotiated rates received no portion of the legislated hedges. Therefore, as noted earlier in this Decision, the Board considers that it would be inappropriate to change the overall rate level payable under those rates in an after-the-fact allocation of the DISCO Deferral Accounts.
The Board notes that rates for AE DISCO and UNCA (previously TransAlta) DISCO were designed based on a cost-of-service study that allocated forecast generation cost components as follows:
• Forecast DISCO energy costs (based on the 1998 hourly pool price record) were allocated to rate class on the basis of forecast energy usage by rate class. • Forecast annual UOV refunds (based on the 1998 hourly pool price record) were spread equally over annual DISCO energy use such that each rate class received the same forecast UOV per MWh.
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• Forecast Reservation Payments were also spread equally over annual DISCO energy use such that each rate class received the same Reservation Payment cost per MWh.
The Board said the following in both Decision U99034 and Decision U99035:
Moreover, under TransAlta’s47 method of allocating the UOV refund (i.e. allocated hourly based on energy) (Board insertion added), 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. [Board emphasis added]
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) divided by forecast DISCO total annual energy use
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 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.
47 Decision U99034 reads “under AE’s and TransAlta’s method of allocating the UOV refund...”
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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.48
In the Board’s view, what is important to note is that the rate design attempted to address the concern that DAT customers see the variation in pool price in each hour and that it not be muted by the UOV refunds. DAT customers would see and be able to respond to the variation in the actual hourly pool price. However, the Board noted that for fixed rate customers, consumption would not be affected in the short term.
Hence, Decisions U99034 and U99035 focused on a fair sharing of the hedges on a forecast basis and a pass-through of hourly pool price variation to DAT customers. The Board recognized that the system of legislated hedges would disappear in 2001. Legislation required the Board to approve a DAT rate that reflected the variation in hourly pool price. 49 Accordingly, the UOV refund allocation method selected by the Board, at that time, attempted to recognize a number of conflicting objectives in the design of the original rates. The original rates were based on a forecast of 2000 pool prices that was set equal to actual 1998 pool prices.
However, in Decisions U99034 and U99035, the Board did not approve a design for DAT rates that allowed pure pool price flow-through as some parties to the PPDA Proceeding suggested. Instead the Board approved a TOU DAT50 (referred to in this Decision simply as TOU) and actual pool price DAT (referred to in this Decision simply as DAT) to allow customers to see different forms of price signals.
The TOU rates were based on the actual pool price record from 1998 and provided only the forecast 2000 pool price in the applicable TOU period:
• For AE, the forecast was based on the actual prices in 1998 for the TOU period in which the rates were in effect.
• For UNCA, the Board accepted TransAlta’s approach that TOU rates should be designed using average 1998 pool costs51 for each TOU interval, rather than the 1998 pool price, to keep each customer class revenue-neutral if the entire rate class used the TOU rate.52
The actual pool price DAT was designed essentially only to allow hourly variation of the pool price to occur around the average 1998 monthly price levels on which the fixed price rates were
48 Decision U99035 pages 24-25; Decision U99034, pages 19-20. 49 Section 31.6 of the EU Act and sections 4, 5(2), and 6 of the Distribution Regulation, AR 168/98 (since repealed by the Distribution Tariff Regulation, AR 84/2000), set out the requirements in designing a DAT. 50 Described as “Option 2” energy charges for AE rates and “Time-of-Use Service” for UNCA rates. 51 I.e. TOU charges were based on the rate class weighted average pool purchase cost over the relevant period. 52 See Decision 2000-11, pages 52-53
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based. That is, in Decisions U99034 and U99035, the Board recognized that a further adjustment was required for DAT customers who were not on TOU rates:
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 the 1998 prices used in the calculation of “H” (as set out in Section 3(b), 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 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.53
In the Board’s view, the important point to note from this quote is that neither TOU nor actual pool price DAT customers were purely pool price flow-through customers, but rather customers who would, on a forecast basis, essentially have their average energy cost brought down to the same level as customers on single fixed price rates (based on the 1998 pool price record) if the TOU and DAT customers consumed energy at the same time as average customers in the fixed price rate class. AE and UNCA TOU customers would have seen a fixed saving relative to the fixed price rate of their respective customer class for using energy in lower price TOU periods.
53 Decision U99034, page 96; Decision U99035, pages 120-121.
34 • EUB Decision 2002-026 (April 18, 2002)
PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding
Similarly, the actual pool price DAT customers did not see actual 2000 average pool price levels because the DAT Rate Adjustment lowered their costs from those levels. Instead, they would essentially see only the actual 2000 hourly pool price variation around 1998 monthly pool price levels, assuming that 100% of the DISCO’s load was hedged in both 1998 and 2000 and the DAT Rate Adjustment worked correctly.54 Therefore, assuming that 100% of the DISCO’s load was hedged to average 1998 levels, DAT customers could pay less than they would have paid under fixed price rates by transferring their usage to hours where the pool price was less than the 2000 monthly average pool price. The DAT Rate Adjustment protected DAT customers from any run-up in the monthly average price relative to fixed price rate customers.
However, in Decision 2000-11, the Board also recognized that DAT load was not 100% hedged to 1998 fixed price rate levels on a forecast basis:
The Board considers that IPCCAA’s arguments regarding DAT design would only have weight if it is assumed that all DAT load is entitled to own sufficient hedges to fully hedge its load even while other customer load is not so entitled. While IPCCAA is correct that not all TransAlta’s load is hedged for an actual Pool Price DAT customer, fixed rate customers similarly do not receive a reduction in the pool price on their entire load through the H-factor. On a forecast basis, all customers are impacted similarly, since TransAlta DISCO’s entitlements hedges are generally insufficient to cover the entire customer load it serves. Clearly, under the H-factor design in Decision U99035, other customers would be required to forfeit some of their rights to the hedge value to fully hedge DAT customers.55
From this quote, what the Board considers important to note is the intention that DAT customers would not be subject to any run-up in average monthly pool price in 2000 over 1998 levels implicit in fixed price rates, except to the extent that the hedges available did not cover the entire monthly load of the DISCO.
In Decision 2000-11, the Board also notes that the “… GAC was introduced to compensate for the difference between a load on pool price flow through and a load on fixed price rates.”56
From this review of the material Decisions establishing the 2000 rates, the Board considers that, in essence, the energy components of all of the rates, including the Option G and DAT rates but excepting the negotiated rates,57 were designed on the basis of 1998 average pool price levels.58
54 If the Adjustment formula is translated into energy hedged with the assumption that 100% of 1998 and 2000 energy is hedged for every hour in the month, then the formula becomes ((PP2000 – UOP2000UOA Weighted Avg) × UOA2000 – (PP1998 – UOP1998UOA Weighted Avg) × UOA1998 ))/ UOA = PP2000 – PP1998 for each hour of the month. 55 Decision 2000-11, page 47 56 Decision 2000-11, page 43 57 UNCA Rate 6600 Temporary Energy Service, UNCA Rate 6700 Real Time Pricing and AE Rate Pool Opportunity Rate Price Schedule 33. 58 The energy components of all of UNCA’s rates, excepting the negotiated rates, were adjusted on an across-the-board basis in Decision 2000-31, dated May 30, 2000 that approved a 2000 Rate Reduction Rider of 1.43% with an implementation date of June 1, 2000. The energy components of all of UNCA’s rates were adjusted
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PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding
The rates were designed to fairly balance the allocation of legislated hedges and the cost of pool purchases as between customers on actual pool price DAT and Option G and customers on fixed price rates on a forecast basis.
The intention of the rate design was that the DAT and Option G customers would essentially see the 2000 hourly variation around 1998 levels on much of their consumption. In effect, the price signals of TOU, DAT and Option G rates were referenced to the single fixed price rates. As the Board indicated in Decisions U99034 and U99035, “DAT customers with typical usage characteristics should be no worse off than if they had chosen fixed price rates.” The Board considers that it would be just as unfair if fixed price rate customers were worse off than DAT or Option G customers with usage patterns similar to the average customer on the fixed price rate as a result of the allocation of the deferral accounts.
In regard to the eventual disposition of UNCA DISCO’s PPDA the Board indicated that:
The Board is also concerned that DISCO customers, particularly those served on the pool price Direct Access Tariffs (DAT), see the appropriate price signals. DAT customer response to pool price improves the efficiency of the market. Therefore, the Board considers that there should be no artificial incentives to keep customers on single price level fixed rates if they prefer the actual pool price DAT or the time-of-use DAT. The Board considers that the eventual disposition of the deferral account balances to customers should reflect this principle.59
In the Board’s view, its clearly expressed intention was that DAT customers and TOU customers would not be subject to an unfairly large proportion of the deferral account allocation relative to customers on single price fixed rates. In fairness, the Board considers that the converse should also hold − i.e. that customers on single price fixed rates should not be subject to an unfairly large proportion of the deferral account allocation relative to TOU and DAT customers or, for that matter, relative to Option G or other fixed rate customers.
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4.2.3 Maintaining 2000 Price Signals & Relationships Among Rates It is quite clear that, in making its rate design findings in Decisions U99034, U99035, 2000-11, and 2000-13, the Board’s objective was to balance competing rate design criteria considering the information that was available at the time. The Board accepted that the 1998 actual pool price record should be used to derive the 2000 rates. As a result, the 2000 forecast pool prices were at the $30-40/MWh level. At that time, the Board did not have “a perfect forecast of 2000” on which a cost allocation could be based.60
on a rate specific basis in Decision 2000-60, dated August 31, 2000. The energy components of all of AE’s rates, excepting the negotiated rates, were adjusted on an across-the-board basis in Decision 2000-19, dated March 13, 2000 that approved a Rider G increase of 0.71% and Rider J increase of 3.79% with an implementation date of April 1, 2000. The energy components of all of AE’s rates were adjusted on a rate class specific basis in Decision 2000- 26, dated May 1, 2000 that approved revised Rider G and Rider J with an implementation date of May 1, 2000. 59 Decision U99099, page 203 60 Transcript 4497
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In this Decision, however, the Board is determining the fair allocation of the actual deferral account balances on an after-the-fact basis. For this purpose in this context, the Board has determined that it must consider whether, on an actual basis, the final rates resulting from the allocation of actual 2000 legislated hedges and “actual” pool purchases as between DAT/ Option G customers and customers on fixed price rates is fair.
Some parties argued that the overall price signals seen by customers in 2000 should be preserved to the degree possible when allocating the Deferral Accounts. The Board accepts, as a laudable goal, that price signal relationships among rates should be maintained to the degree possible. However, as discussed earlier, the Board has concluded that maintaining the level of the price signals present in the approved rates for any class is not possible without cross-subsidization from other customers. By its nature, an after-the-fact allocation of the DISCO Deferral Accounts cannot change the price signals that were provided to any customer during the year 2000, it will only impact the final economics related to 2000 energy purchases.
In the Board’s view, the role of the 2000 price signals was to allow each customer to change its behavior to its best advantage in the circumstances. However, as FIRM indicated, “no one is able to go back to 2000 and change their hourly consumption based on price signals determined at the conclusion of this [allocation] exercise.”61 Similarly, at this stage, no customer is able to exercise any option it may have to transfer to another rate for the year 2000.
While customers did not know how the deferral accounts would be disposed of, the Board recognizes that for many unsophisticated customers the 2000 rates did provide the only price signals in the year 2000. More sophisticated customers would have realized that the price signals implicit in the rates were subject to the disposition of the deferral accounts.
For customers served under fixed rates (i.e. TOU and single price fixed price rate customers), the actual 2000 hourly pool prices and the overall level of 2000 energy costs incurred on their behalf by the DISCO were totally masked in 2000.
For DAT and Option G customers, the actual 2000 hourly pool price variation was apparent. However, the DAT Rate Adjustment for DAT customers and the GAC for Option G customers masked the overall level of their 2000 energy costs from those incurred on their behalf by the DISCO. The imposition of a deferral account added further uncertainty to the price signals seen by these sophisticated customers.
While most fixed rate customers would have made their consumption decisions in year 2000 based upon the price signals provided by the approved tariffs that they saw, more sophisticated customers were aware that the economics implicit in the rates would likely be changed as pool prices increased.
The Board considers that these facts are important in assessing the fairness of the affect that the hourly vs. annual allocation of the UOV refunds has on the total final economics for fixed rate, Option G and DAT customers.
61 FIRM Argument, page 65
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PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding
In the Board’s view, an after-the-fact allocation of the UOV refunds that leads to larger variations in the total energy cost allocations to customers who saw the same fixed price rates regardless of the actual 2000 pool price in the hour their consumption occurred would be unfair to those customers on fixed rates. When they made their consumption decisions in response to the price signals in the 2000 rates, particularly in the first half of 2000, many less sophisticated fixed rate customers would not have known that they would be assessed higher PPDA allocations for consumption in certain hours.
In support of a monthly allocation of UOV refunds, IPCCAA indicated that:
Specifically, the seasonal variations in Pool Price in 2000 were dramatic (Board emphasis added). The difference between the highest and lowest average monthly price exceeded $200/MWh. The 1998 Pool Price record, that formed the basis for 2000 rates, saw the difference between the highest and lowest average monthly price of less than $27/MWh.62
AE DISCO maintained that if these pool price variations were “dramatic” on a seasonal basis then the fluctuations must be characterized as “severe” on an hourly basis. As the analysis of pool price fluctuation in AE’s Argument demonstrated, more than 400 hours of the 8,784 hours in the year 2000 saw pool prices above $500/MWh.
Therefore, in the Board’s view, it would be fundamentally unfair to allocate the net deferral account so as to charge fixed price rate customers the full hourly variation in pool price experienced by the utility in purchasing energy to serve these customers without recognizing the hourly benefit of the UOV received by the DISCO with respect to the purchased energy. In the Board’s view, therefore it would be fairer for fixed rate classes to mute the variation in the total hourly energy charge to each fixed rate class by allocating the UOV refunds on an hourly basis if the pool price component is allocated on an hourly basis. The Board considers that it would be unfair for fixed classes to see all of the hourly variation in the pool purchases.
The Board considers that it would be similarly unfair to impose an actual UOV allocation method that produces an after-the-fact result that would effectively remove all of the hourly pool price variation seen by the Option G and DAT customers. However, the Board notes that an after-the-fact hourly UOV allocation does not change the fact that DAT and Option G customers will still see the actual pool price on each MWh consumed in each hour of the year.
The Board also notes that use of a cost-based allocator derived from allocation of the pool price on an hourly basis combined with an hourly UOV allocation ensures that the DAT and Option G customers will, in their final overall charges, see at least some of the 2000 variation in hourly pool price to which they responded.
In addition, the Board notes that the muted level of the 2000 variation in hourly pool price is more reflective of the levels in variation that were expected when the rates were designed.
62 IPCCAA Argument page 27
38 • EUB Decision 2002-026 (April 18, 2002)
PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding
The Board agrees that it is just and reasonable for DAT and Option G customers to retain a portion of the benefits/costs resulting from their consumption choices relative to what they would have been if billed on fixed rates. However, the Board can see no convincing reason that they deserve to receive any greater benefit relative to fixed rates than what the Board considered would be available when the original rates were designed.
Therefore, the Board considers it more important that the deferral account allocation method arising from this Decision provide a fair allocation among Option G, DAT and fixed rate classes than that it maintain the exact price signal relationships among the fixed price rate classes and the DAT and Option G customers implicit in the rates in effect in 2000.
When the 2000 rates were designed, the Board expected all fixed rate customers to see fixed energy charges that were based on the 1998 pool price record with minor adjustments. The Board expected DAT and Option G customers to see 1998 average pool price levels with the 1998 hourly price variation around those levels. As AE indicated, 2000 pool prices were envisaged to be in the range of $30-$40/MWh. Correspondingly, the accompanying forecast entitlement amounts were expected to be relatively flat by hour. Occasional price spikes were expected to occur when temporary supply-side shortages occurred. Option G and DAT customers would realize some benefit from responding to these spikes.
When the Board approved the DAT and Option G rates, the pool prices and variation in pool prices were anticipated to be at 1998 levels. Therefore, when it approved the DAT and Option G rates, the Board anticipated that, relative to fixed rate customers, both DAT and Option G customers would only see savings at the level of 1998 pool price variation. However, due to the unexpected increase in pool prices (4.7 times forecast) caused primarily by continuous supply- side pressures, the 2000 average pool price levels and hourly variation proved to be markedly different than the 1998 levels on which the 2000 rates were based. During 2000, the pool price averaged in excess of $130/MWh, with over 2800 of the 8,784 hours reporting a pool price of $100/MWh or more and over 400 hours reporting a pool price of $500/MWh or more. As a result, in 2000, both pool price and the related UOV refunds fluctuated significantly more than expected from hour to hour.
Therefore, DAT and Option G customers saw markedly greater variations in hourly pool prices in 2000 than expected at the time their rates were designed. In the end result, after taking into account the portion of the PPDA each is allocated, DAT and Option G customers may have still saved more relative to fixed rate customers in terms of final 2000 energy unit costs than would have been expected when the Board designed the rates. Additional savings relative to fixed rates may arise due to the much higher average hourly price variations that actually occurred in 2000.
If the Board were to allocate the UOV refunds on a monthly basis to determine the cost-based allocator, the savings would be much greater than expected vis-à-vis fixed rates and in the Board’s view, excessive relative to the variations around which the rates were planned and set. Instead, the net savings relative to fixed rates for DAT/Option G customers will be somewhat muted by the hourly UOV refund allocation determined in this Decision.
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PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding
Having decided that an hourly allocation of Component 163 to determine the cost-based allocator is just and reasonable in the circumstances, the Board considers that the UOV refund amount must be allocated on a similar basis to be fair to fixed rate customers. Otherwise, in the Board’s view, the actual benefits of low-cost regulated generation would flow unfairly to some customers (DAT/Option G) who were already able to realize effective savings (relative to fixed price rates) in response to 2000 price signals by reducing their consumption in high cost hours and increasing their consumption in lower cost hours.
The allocation of UOV refunds on an annual basis was a fair way to allocate the hedges on a forecast basis considering the desire to provide hourly price signals. However, this method is not fair for PPDA allocation purposes given that actual UOV refunds were 5.9 times forecast. If the UOV refund components of the PPDAs were allocated to classes on a monthly basis, price responsive customers such as DAT/Option G could save much more than expected relative to the fixed price rate customers due to the unexpectedly large variation in pool price and UOV refunds.
IPCCAA submitted that the opposite should also hold:
The allocation of the deferral accounts should not leave fixed rate customers better off than had they been DAT loads. Through the deferral accounts all customers have, to a degree, become actual pool price DAT customers.64
The Board agrees that allocation of deferral accounts should not leave fixed rate customers better off than DAT customers in relation to the pool purchases costs incurred by the DISCO on their behalf. The Board notes that the determined cost causation based allocation methodology will ensure that any cross-subsidization in pool purchases is minimized.
However, the Board recognizes that fixed rate customers chose not to be DAT customers and did not expect to have the opportunity to respond to the hourly pool price variation in order to potentially reduce their energy charges below those of other fixed rate customers. Nor did the majority of fixed rate customers have the sophistication to understand (or reason to gain the sophistication since their rate was fixed and they likely did not understand the potential implications of the PPDA) or to react to the hourly pool price that affected the DISCO’s hourly energy cost to serve them.
On balance the Board considers that the DAT and Option G customers would receive an appropriate level of benefits/costs relative to fixed rates as using the cost-based allocation methodology, though the exact price relationship between them and fixed rates implicit in the 2000 rates will not be preserved.
For all of these reasons, to ensure that both fixed rate and DAT/Option G customers are treated fairly and reasonable in the circumstances, the Board has concluded that the allocation of pool purchases costs (Component 1) on an hourly basis to determine the cost-based allocator requires the muting effect of an allocation of UOV refunds (Component 2) on an hourly basis.
63 I.e. the pool purchases component of the deferral account reflecting increased pool price over forecast. 64 IPCCAA Argument Page 28
40 • EUB Decision 2002-026 (April 18, 2002)
PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding
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4.2.4 Fairness Within Customer Classes For classes with both TOU and non-TOU customers, the Board considers that when customers decided to take TOU service, TOU customers expected only to save the differentials (based on the 1998 pool price record) between the non-TOU tariff and the TOU tariff for load transferred to lower-price TOU periods. Similarly, when they decided to take TOU service, TOU customers in a given customer class expected only to pay the differentials between the non-TOU tariff and the TOU tariff for consumption in higher-price TOU periods. The Board notes that those expected differentials would be essentially retained through the allocation methodology determined in this Decision. Therefore, the Board considers that these customers would receive fair treatment for their consumption decisions relative to other customers in the customer class.
Similarly, for customer classes containing only TOU customers (i.e. UNCA Rate 6300 Large General Time-of-Use Service and Rate 6400 Transmission Service), the customer expected only to receive the savings relative to other customers in the class that would result from the differentials between the different TOU periods according to when their consumption actually took place relative to other customers. Again, the Board notes that expected differentials would be essentially retained through the allocation methodology determined in this Decision. Therefore, the Board considers that these customers would also receive fair treatment for their consumption decisions relative to other customers in the customer class.
Similarly, each DAT and Option G class customer will have a portion of the deferral account directly allocated to them depending upon their usage characteristics and would also receive fair treatment for its consumption decisions relative to other customers in the customer class.
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4.2.5 Use of 2000 Rate Design Principles As previously noted, some parties submitted that the rate design used in the last Phase II (i.e. 1999/2000), including the methodology used to allocate the forecast legislated hedges to customer classes, should be changed as little as possible in the allocation of the PPDA balances.
The Board considers that a fair, after-the-fact allocation of 2000 UOV refunds must consider all of the UOV refunds received by the DISCO in 2000 and not just the difference between the forecast UOVs and actual UOVs. If the portion of the total actual UOVs already paid to customers through the rates (i.e. the forecast UOVs) were allocated on an unfair basis, then the remaining UOV refunds would have to be allocated on a basis that would compensate for that unfairness at any rate. Thus, the end result would be the same.
It is important to note that, in 2000, both the pool purchase component increasing the DISCO’s hourly deferral account and the UOV component decreasing it were essentially driven by the increases in hourly pool price over the forecast hourly pool price. In the Board’s view, a fair allocation of the PPDA balances requires the allocation of actual 2000 UOV Refunds in such a way as to ensure the equitable sharing of the benefits of low-cost generation among all customers.
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PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding
In AE DISCO’s case, the hourly variation in demand (i.e. volume) had no effect on the pool purchases component of AE’s PPDA since it was based only on forecast load at actual pool prices. Similarly, volume had an insignificant effect, overall, on the pool purchases component of UNCA’s PPDA. UNCA’s total customer load in 2000 was not significantly different than forecast.
Volume had a much greater effect on the hourly UOV refund component of the PPDAs. Even though the percentage of total hourly UOV refunds to which the DISCO was entitled was fixed by legislation, because UOV refunds increased as the spread between UOP and pool price increased in a given hour, UOV refunds tended to be much higher in peak hours and lower in off-peak hours. Peak hours tended to be the times that supply-related shortages (i.e. during times of reduced volumes of supply and/or increased volumes of demand) exerted the most upward pressure on pool price.
The Board agrees with the following observations of IPCCAA:
Circumstances in 2000 have differed in a manner that would make an annual allocation unworkable. Specifically, the seasonal variations in Pool Price in 2000 were dramatic. The difference between the highest and lowest average monthly price exceeded $200/MWh. The 1998 Pool Price record, that formed the basis for 2000 rates, saw the difference between the highest and lowest average monthly price of less than $27/MWh.65
The Board would extend IPCCAA’s observation to note that hourly variations were even more dramatic. Therefore, the Board is of the view that a monthly allocation of UOV refunds would not mitigate the effects of the hourly excursions of pool price, which drove both the UOV refund and the pool price components of the PPDAs.
The Board notes that the differential between forecast pool price and forecast entitlements, at the time the 2000 rates were designed, was in the order of $10/MWh. Forecast customer rate classes were all given the same annual H-factor based on an allocation of UOVs using annual rate class energy since the variation in annual H-factor by rate class was not considered significant. However, the actual, average differential between pool price and UOV refunds turned out to be almost three times the forecast differential. If they had been forecast, the much higher level of UOV refunds might well have led to an hourly allocation of the legislated hedges to ensure that the benefit related to existing low-cost generation was equitably shared by new and existing customers since the DISCO entitlement profile would have taken on added weight.
For example, if the higher levels had been forecast, it would likely have been necessary to determine an annual H-factor by rate class to properly reflect the correlation between forecast rate class hourly pool purchases at the pool price and the offsetting forecast hourly UOVs. The allocation of UOVs using hourly energy to determine annual H-factors by rate class would not have destroyed the hourly pool price signals to flow-through customers but would have more accurately set the fixed price rate base for all customer classes including the Option G and actual
65 IPCCAA Argument Page 26
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PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding pool price DAT customers. Certainly the price signals to all customers would have been very different.
The Board considers that providing fixed rate customers of the DISCO who purchased energy in high pool price hours with the benefit of the hour’s higher UOV would mitigate the higher pool price assigned to those customers. In the Board’s view, if fixed rate customers were assessed the higher cost of energy during periods of high pool price as well as a lower monthly average UOV for that same hour, fixed rate customers of certain classes would receive a disproportionate share of the net deferral account balance.
For all of these reasons, the Board considers that an annual or monthly allocation of the UOVs (Component 2) to fixed rate customers according to the 2000 Rate design would fall short of fairly addressing the allocation of the unexpected increase in the deferral accounts assuming pool purchases (Component 1) are also allocated hourly.
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4.2.6 Impact of Demand Side Response on UOV Allocation Some parties suggested that the overall pool prices were lower in 2000 due to the demand side response of some customers, who should, accordingly, receive some corresponding benefit in the allocation of the PPDA balances.
IPCCAA provided detailed evidence to show how a monthly UOV allocation would, in its view, properly allocate a portion of the UOV refunds from high pool price hours to loads that curtailed in response to those high pool prices, whereas an hourly UOV allocation would provide no UOV refund in respect of curtailed load.66 In argument, IPPCCA submitted the following:
The mechanism by which loads “retain the benefits of their actions” has two components—reduced allocation of the Pool purchase component of the deferral account in hours when load was curtailed (the part acknowledged by the FIRM Group) and also an entitlement component whereby the load that curtailed should be able to capture the entitlement value associated with their curtailed load (the part ignored by the FIRM Group). Absent any price responsiveness, these loads would have received a share of the UOV refunds. Providing a share of the UOV refund to the curtailed load would leave other loads no worse off, and potentially better off due to the downward pressure on Pool Price resulting from lower load.
For a load that curtails in an hour with a high Pool Price, an hourly Pool purchase deferral allocation does not allocate Pool purchase amounts to curtailed load and this is appropriate. But an hourly UOV refund allocation improperly excludes curtailed load from the benefits of the high UOV refund in such an hour. An hourly mechanism for allocating UOV refunds diminishes the strength of the market-determined price (Pool Price) by requiring the load to consider not just avoided Pool purchases, but also foregone UOV refunds in their curtailment decision. Exhibit 911 provided an example of how the DAT provided a portion of
66 Exhibit 911
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the legislated hedge related to the hour of curtailment to a curtailed load. The deferral account allocation should accomplish the same in respect of Option G. An hourly allocation of UOV refunds, as suggested by the FIRM Group, does not accomplish this.
IPCCAA’s Argument (page 28) clearly demonstrates that the hourly UOV allocation has exactly the opposite effect suggested by the FIRM Group: an hourly UOV allocation masks Pool Price signals, allocates less to loads that had higher use in on-peak periods and claws back benefits from curtailed load. The FIRM proposal would claw back benefits from customers who curtailed load. As described earlier, there are two components to the benefits of curtailed load: reduced Pool purchases and retaining the entitlements in respect of the curtailed load. The FIRM proposal for hourly allocation of UOV refunds would prevent curtailed loads from receiving any credit for entitlements in respect of curtailed load.67
The Board notes the net impact on the DISCO deferral account due to the consumption decisions of customers was effectively muted because the pool price was the primary driver of both the pool purchases and the UOV refund components of the deferral account. While the curtailment of load in a given, high-priced hour may have exerted downward pressure on the pool price in that hour, it would have had a muted net effect on the DISCO PPDA balances since the UOV refunds would be commensurately reduced depending on the hedged portion of the DISCO’s load. If, for example, 80% of the load were hedged then, a $1.00/MWh reduction in the pool price component of the deferral account would translate into a $0.80/MWh reduction in the UOV refund and, therefore, only a $0.20/MWh reduction in the net DISCO deferral account balance. Even that muted effect may have been offset if the load curtailed in the higher-priced hour was transferred to an hour of otherwise lower pool prices and exerted upward pressure on price during that hour.
Further, through the allocation of the pool purchases component of the deferral account determined in this Decision, the customer class of the customer who curtails or transfers load will receive the total benefit of curtailment or purchasing their energy in lower priced hours.68 Therefore, since any effect on the net DISCO PPDA of a pool price reduction caused by customer class curtailing or transferring load to lower priced hours was muted at best, the Board is not persuaded that such a customer class should see the larger variation effect to which a monthly allocation of UOV refunds would lead.
Customers who curtailed but did not consume electricity in another hour in 2000 would be more likely to have exerted downward pressure on the pool price since no load would have been transferred to other hours in which the pool price would have otherwise increased as a result. Again, the Board notes that the pool purchase allocation method ensures that the customer, or its class, will see the full value of the benefit of that curtailment through the reduction of the pool
67 IPCCAA Reply, pages 22 and 23 68 Smaller customers in fixed rate classes will typically see a reduction in cost assigned if their class uses energy in lower pool price periods. Customers with demands greater than 2 MW will see a direct reduction in cost assigned.
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purchase costs assigned to it. If the overall net PPDA balance is lower due to their curtailment, the amount allocated to them will also be correspondingly lower.
In the Board’s view, there are three reasons why curtailing customers should not receive any greater share of the outstanding UOV refunds than other customers as compensation for the reduction in pool price that may have resulted from their curtailment. The reasons are summarized as follows:
1. As discussed above, any reduction in pool price would cause only a muted reduction in the net DISCO PPDA balance due to the offsetting reduction in the UOV refund.
2. The Board considers that only the users of electricity (not curtailed load) are entitled to the UOVs in a given hour. Only users of electricity would receive the value of the regulated plant (in the absence of the legislated hedges) if the plant produced electricity at regulated prices. In 2000, unforecast new load was at least equal to any unforecast load curtailment since the total actual DISCO load in 2000 was very near the forecast levels. The actual UOV refunds are available to be allocated to this total 2000 actual DISCO load comprising both new and existing load. If an hourly or monthly allocation of UOV refunds would lead to a greater share of those refunds being given to customers who curtailed load in certain hours, new and existing customers who consumed electricity in those hours would receive a lesser share. In the Board’s view, such a result would be inconsistent with the EU Act, which requires a fair allocation of the legislated hedges only to users of electricity.
3. The Board considers that, with the exception of Option G,69 none of the rates were designed to provide any extra credit (beyond the savings from not consuming) for curtailing load entirely. All other rates were designed only to provide lower prices for transferring load to lower-priced hours. The H-factor credit and DAT Rate Adjustment were reductions based on $/MWh of consumption. Hence, other than Option G, customers would not have expected any extra credit merely for curtailing load in a particular hour.
Furthermore, even though single-price fixed rate customers had no incentives to transfer load to hours in which the pool price was lower, since those customers paid the same fixed price for consumption in any hour of the day or year, the method of allocating pool purchase deficiencies to rate class determined in this Decision will result in those customer classes being charged a higher portion of the deferral account if they consumed in higher priced hours.
IPCCAA submitted that an hourly UOV allocation would grant additional hedges to loads that purchased more of their requirements at times of higher pool price as if they had paid for additional hedges when there was no basis to conclude that they had done so. In the Board’s view, IPCCAA’s argument does not consider the likelihood that most additional unhedged load in 2000 arose from new or growing customers rather than from consumption decisions of existing customers.
69 See Section 4.3
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In the Board’s view, if the hourly pool price, rather than the monthly or annual pool price, is used to determine the net deferral account balances, then the hourly UOV refund, which is driven by that hourly pool price and hourly entitlement volume, must also be used. If the Board were to do otherwise, the hourly increases to the deferral account driven by the pool price would be not be matched with the hourly decreases that are also driven by both the hourly pool price and hourly entitlement volume. In the Board’s view, new customer load would be treated unfairly as a result, contrary to the requirement of the EU Act that both new and existing customers share equitably in the benefits of existing low-cost generation.
The Board also disagrees with IPCCAA because fixed rate customers were not provided with, and could not respond to, an hourly pool price signal. It would be unfair for these fixed rate customers to be effectively penalized for their consumption of electricity in higher-priced hours when the majority of them were relatively unsophisticated and, without an understanding of the potential effects of the allocation of the PPDA, had no economic basis on which to alter their consumption decisions.
Further, the DISCO’s had a larger proportion of UOVs in the peak hours and it would be unfair if unforecast new customers were not to receive their share of that additional UOV entitlement considering the increases in pool price that simultaneously increased the pool price and the UOV refunds. In other words, new fixed rate customers would not be allocated a fair share of UOV refunds in higher-priced hours, since customers that either curtailed or transferred load would receive them.
In the Board’s view, if fixed rate customers were assessed the higher cost of energy during periods of high pool price and only credited the lower monthly average UOV for that same hour, certain fixed rate classes would receive a disproportionate share of the unhedged portion of the deferral account balance relative to DAT, Option G and even other fixed rate classes with different growth rates. Considering that the unexpected increase in the deferral account was almost entirely due to pool price increases rather than any increase in overall DISCO consumption or unhedged load, the benefit of existing low-cost generation would not be equitably shared by new and existing customers as required under the EU Act.
Therefore, the Board considers that all customers of the DISCO who purchased energy in high pool price hours should receive all the benefits of the higher UOV volume in those high pool price hours. Customers that curtail should not receive any of the benefit of the higher UOV volume in those hours.
In conclusion, the Board is of the view that the consumption decisions of customers had only a muted effect, if any, on PPDA balances in 2000. Rather than consumption decisions, it was primarily the hourly load (be it new or existing) greater than the hourly-hedged volumes and the higher hourly pool price that drove both the pool price component and the UOV component of the PPDA balances. Therefore, the Board considers that the allocation method chosen for actual UOV refunds should neither unduly penalize nor reward the consumption decisions made by fixed rate or price responsive customers in the year 2000. Accordingly, the Board considers that the hourly allocation of the UOV refunds determined in this Decision would be fair in this respect.
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Notwithstanding this conclusion, the Board in a later section of this Decision dealing with Option G system benefits has recognized that Option G customers should receive a credit to reduce their share of the PPDA allocated to them to recognize that the consumption decisions of this particular rate class may have benefited all customer classes.
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4.3 Fairness Considerations (Option G) 4.3.1 Introduction Option G customers will have a larger per MWh deficiency rider relative to other customer classes arising from the disposition of the DISCO PPDAs. The Board notes that the primary reason for this larger deficiency rider is the much smaller portion of their actual net 2000 energy costs (i.e. energy purchase costs and allocated UOVs) that Option G customers paid relative to other customer classes. While the Board is persuaded that the methodology determined in this Decision leads to a fair, cost-based allocation to all classes,70 the Board has reviewed the considerable amount of argument made specifically in relation to Option G customers to determine if there is any convincing reason for this class to be cross-subsidized by other customer classes.
As background to its consideration of the Option G fairness issues, the Board notes the following:
1. IPCCAA.UNCA DISCO #2-3: In the design for Option 21/G, customers were to be exposed to the hourly pool price, as an incentive to be price responsive to the hourly price, while at the same time making them approximately revenue neutral to the fixed price rate through the GAC, absent any response to pool price, and based on average pool price for the month. Initially the GAC was a charge, over time it reduced towards zero, and was removed in the latter part of 1998, through the Negotiated Settlement. It was reintroduced in January 1999, in the same format, and due to higher pool prices became a credit. TransAlta filed for acknowledgment with the Board on January 22, 1999, the process for the calculation of the GAC.
The revenue from Option 21/G customers and the level of the GAC were forecast, recognizing that these customers would be ‘revenue neutral’, on a forecast basis, to standard rates.71
2. The Board’s Findings in Decision 2000-11: However, the Board notes that the GAC was introduced to compensate for the difference between a load on pool price flow through and a load on fixed price rates. The Board agrees with TransAlta that the revised GAC in TransAlta’s
70 The Board agrees with IPCCAA and UNCA that UNCA should increase the January and February Option G revenue by $6.70/MWh or $1.9 million over the two months ($6.70/MWh x 286.8 GWh from Schedule 8- G). With that adjustment, the Board is convinced that its methodology leads to a fair cost-based allocation to Option G customers. 71 Exhibit 319
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October 25, 1999 letter would maintain the form of the existing GAC in Option 21, in that the GAC compensates for the differences in generation charges between the fixed and pool price rates. Under the revised GAC and the other refiled rates, the reconciliation is independent of the H-factor, since it is equal in both the fixed and pool price rates. Therefore, the Board agrees with TransAlta that the revised GAC in TransAlta’s October 25, 1999 letter is the form that the final GAC arising out of this Decision should take considering the form of Large General Time-of-Use Service Rate 6300 and Transmission Service Rate 6400. Therefore, the revised GAC should be implemented on the same date as Rates 6300 and 6400.72
3. The Option G Rate schedule approved in Decision 2000-1273:
Availability Option G applies to qualifying customers billing on Rates 6200, 6300 or 6400. This Option replaces the Generation Service Charge of those rates as follows. It also applies a modified Option F Credit Level as described below. All other charges are billed as described in the Rate.
Generation Service Charge Energy Charge: Power Pool of Alberta Hourly Price Regulated Generation Credit (0.67)¢/kWh Generation Access Charge/Credit: $/kW/Month determined monthly
Plus […]
4.3.2 Board Jurisdiction respecting Option G Rates ANC/MW submitted that UNCA’s application effectively requested that the Board reset the 2000 rates with the benefit of perfect hindsight. ANC/MW submitted that the Board had no jurisdiction to effectively and retroactively change the 2000 rates, including Option G, unless the criteria of section 57 of the EU Act were satisfied or the Board’s decisions establishing the rates had been set aside by the Court of Appeal. ANC/MW submitted that neither was the case.
ANC/MW submitted that Decision U99099 did not mention that PPDA treatment applied to Option G, which was consistent with ANC/MW’s understanding of TransAlta’s intentions:
1) Notwithstanding that TransAlta was aware that the GAC could vary from forecast, TransAlta did not apply to have variations in the GAC included in the deferral account; 2) When TransAlta sought to collect interim payments on the deferral account, it did not apply to recover any of the deferral account from Option G; and 3) TransAlta assured ANC/MW that it did not intend to attempt to collect the deferral account from Option G.
72 Decision 2000-11, page 43 73 Schedule A, page 48, part of the Option G rate schedule
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In the first place, the Board disagrees with ANC/MW that Decision U99099 suggests that Option G would not be subject to the allocation of deferral account balances at the end of the test period. The establishment of DISCO PPDAs in Decision U99099 was in general terms and made no indication that deferral account balances would be allocated only to specific rate classes or options. In the Board’s view, Decision U99099 cannot be taken as an indication that Option G customers would not be allocated a fair portion of the outstanding PPDA balances merely because Option G was not expressly made subject to the allocation of the PPDA balances. The Board also rejects the argument that it is without jurisdiction to allocate the PPDA balances to Option G because to do so would amount to retroactive rate-making in the absence of proper criteria for the exercise of the Board’s review and variance power under section 57 of the EU Act. Earlier in this Decision,74 the Board concluded that the allocation exercise is not retroactive because the approval of the 1999/2000 tariffs was expressly subject to the eventual disposition of the PPDA balances after the end of the test period. In the Board’s view, the 2000 tariff was unique in this respect and the Board requires no further authority to allocate the PPDA balances to all customer classes to which the PPDAs were applicable. Since the Board is of the view that Option G customers are no different than other customers classes in this respect, the Board considers that it has jurisdiction to allocate a fair share of the DISCO PPDA balances to Option G customers.75
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4.3.3 Board Review of Other Option G Fairness Concerns ANC/MW submitted that UNCA should not be entitled to pass on to customers the greater than forecast GACs in 2000 when TransAlta retained the $15 million overpayment by Option G customers in 1998.
The Board notes that TransAlta’s retention of the overpayment in 1998 was part of the 1998 Negotiated Settlement:
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.
74 See also Decisions 2001-45 and 2002-025. 75 The allocated deferral account balances will be recovered prospectively typically by way of a rate class deficiency rider applied to the distribution tariff of customers who were on Option G in 2000. Customers who have become transmission-connected customers with service supplied by the TA, or have become industrial systems, will be billed directly.
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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.76
In Decision U99035, the Board found as follows:
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
76 Decision U99035, page 50
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with the arrival of full competition in 2001 more options should be available to all customers.77
The rate schedule approved by the Board for year 2000 included the GAC. Therefore, regardless of how it was developed, GAC was a Board approved 2000 Rate. The Board agrees with UNCA that the elements and negotiations that led to the design of Option G prior to 2000 are not relevant to the issue of allocating a pool price deferral account that arose in 2000 when Option G was a rate option already approved by the Board.
ANC/MW also submitted that there were at least four fundamental, distinguishing aspects of Option G:
1) the goal of Option G was to create an economic incentive to encourage price- responsive load to respond to price signals and other market conditions; 2) by giving the incentive to Option G to respond to market conditions this provided benefits to TransAlta and its customers; 3) Option G customers responded to these incentives on a real-time basis; and 4) Option G was a negotiated business arrangement. As such, changes were only made to this arrangement on a “going forward” basis.
While the Board agrees that the goal of Option G was to create an economic incentive to encourage price-responsive load to respond to the variation in the hourly pool price, the Board considers that the dynamics of Option G were very similar to the DAT. Both DAT and Option G charged the customers the hourly pool price offset by a monthly credit that was essentially forecast to reduce their energy charges to the levels of fixed rate classes (based on the 1998 pool price record) if the DAT/Option G customers consumed on the class average basis.
In the Board’s view, the quid pro quo for Option G customers adjusting consumption and freeing up supply−i.e. that they would have the opportunity to reduce their average electricity rates from those of fixed rate customers−is also maintained by the allocation methodology determined in this Decision. After allocation of the PPDA balances, the effective 2000 economics of Option G customers will be better than the economics of an average fixed rate class customer if the Option G customer, on average, consumed energy in lower costs periods than those in which average consumption of the fixed rate classes occurred in 2000. In fact, post-allocation, Option G customers will potentially save more in effective pool purchase charges than would have been expected relative to the fixed price rate customers when the Board designed the 2000 rates because the 1998 pool price differentials on which the 2000 rates were based were much lower than actual 2000 differentials. If the Board were to allocate the UOV refunds on a monthly basis, the savings to Option G customers would be even greater relative to fixed rates and, in the Board’s view, excessive relative to the 1998 differentials around which the 2000 rates were planned.
Parties submitted that the consumption decisions of Option G customers likely caused other customers to benefit as a result of the attendant decrease in pool prices and the DISCO PPDA
77 Decision U99035, page 50
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balance. Although ANC/MW considered hindsight analysis of these benefits to be inappropriate, ANC/MW also considered it clear that the benefits had been provided.
The Board agrees with ANC/MW that “The Board approved these benefits as being in the public interest78 and with higher pool prices and greater response, these benefits were also likely greater than forecast.” The Board also agrees with UNCA that, as a result of the PPDAs, any extra benefits attributable to Option G customers lowering average pool prices for the year 2000, will reduce the net DISCO PPDA balance to be charged to all customer classes, including Option G. Option G and other classes will all receive a portion of this benefit since the pool purchases component of the PPDA allocated to each class will have been reduced if DAT and Option G customer curtailment reduced the overall and DISCO pool purchases components. However, no party attempted to quantify any such benefits and they are, therefore, theoretical.
In any event, these benefits can be considered as no more than incidental. In the Board’s view, the customer classes curtailing or transferring load to lower pool price periods would receive all of the benefit to which they are entitled by the reduction in the pool purchase costs assigned to them and a correspondingly smaller allocation of the net PPDA balance to them. If the overall net PPDA balance is lower as a result of customers’ consumption decisions, the amount allocated to them will also be correspondingly smaller. In the Board’s view, there is no obligation to share any incidental benefits that arise from customer consumption choices, even if they could be quantified.
In addition, ANC/MW argued that UNCA had focused solely on reallocating UNCA’s costs and completely ignored the costs incurred by Option G customers to facilitate their responses to the pool price beyond their direct electricity costs. However, the Board considers that the costs incurred by Option G customers to participate in Option G in 2000, including carrying costs of prior year investments, were incurred at their risk. In the Board’s view, these costs should not affect the fair allocation of the DISCO PPDAs to customer classes. For the reasons given earlier in this Decision, once the UNCA deferral account was established, it should have been clear that there could be an after-the-fact change in the economics inherent in the rates upon the fair allocation of the DISCO deferral accounts to customers.
ANC/MW also argued that UNCA’s approach ignored the costs that were avoided by TransAlta because Option G customers responded appropriately to pool price signals, thereby reducing pool prices and the ultimate amount in the deferral account - i.e. the Option G benefits for which TransAlta contracted).
The Board notes that under the methodology determined in this Decision, Option G customers would see a portion of the deferral account based only on the Option G customer’s average pool price purchase costs. According to ANC/MW, these costs averaged approximately 2/3 of the pool purchase costs caused by other customers.
The 2/3 cost factor is confirmed in Appendix 2 (Column C), which shows an Option G average pool purchase unit cost of $85.87/MWh (for the January to August 2000 period) compared to a UNCA average pool purchase unit cost of $138.31 (excluding Option G; for the January to
78 Decisions U96053 and U99035
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December 2000 period). The Board notes that the Option G pool purchase unit cost was 84% of the pool purchase unit costs caused by other customers when compared over the same January to December 2000 period.79 In addition, as noted above, under the Board’s determined allocation method, Option G customers retain their direct pool purchase savings as well as the indirect share of any average pool price reduction arising from their curtailments and load transfer due to the reduction in the overall DISCO deferral account.
ANC/MW submitted that UNCA’s approach ignored the evidence that, if the Board were to redesign rates for 2000 based on present knowledge, “[w]e would have had larger time-of-use differentials and other incentives for customers to curtail at high-priced periods.”80 Instead, ANC/MW considered UNCA’s position to be a request for the Board to “claw back” some of the benefits achieved by Option G customers by responding to price signals in place in 2000.
Some parties suggested that if the Board had designed rates based on the same principles employed in Decisions U99034 and U99035, the Board would have designed rates to effect larger TOU differentials and incentives for curtailment. The Board is not convinced that would necessarily have been the case. As this Decision indicates, if the actual variation in 2000 pool price was forecast at the time the 2000 rates were designed, the allocation of the UOV refunds might have been done on another basis that would have lessened the incentives to transfer load that were seen in the rates that were in effect in 2000.
The Board agrees with ANC/MW and UNCA that, on a forecast basis, “given the dynamic nature of Option G, it was never intended that revenue neutrality would actually be achieved”.81 However, the Board considers the principle of revenue neutrality should not be discarded when determining an allocation methodology for the 2000 PPDA on an actual basis.
The Board considers that preserving the 2000 economics for Option G customers would require even greater changes to the final 2000 economics for fixed rate customers. At any rate, it was obvious that establishment of the DISCO deferral accounts could result in an after-the-fact change in the effective incentives implicit in the rates in effect in 2000 as caused by the fair allocation of the DISCO deferral account to customers. As discussed earlier, the Board considers the price signals in the 2000 rates to have been effectively interim until final disposition of the PPDA Balances.
For all of these reasons, the Board does not consider any of the fairness concerns raised by Option G customers as discussed in this section to warrant an adjustment to the cost-based allocation methodology determined by the Board in this Decision.
However, the Board considers Option G load to be somewhat different from the load placed on the system by other rate classes, which raises different fairness concerns. The Board will deal with this difference in the next section.
79 Using data from Exhibit 314 for the Jan 2000-Aug 2000 period. 80 Transcript Volume 26, Cross-examination of FIRM, p. 6126, line 7 to p. 6127, line 4. See also Transcript Volume 25, Evidence of ANC/MW, p. 5884, line 17 to p. 5885, line 12. 81 Transcript page 5850-5855
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4.3.4 Board Determination of Option G System Benefits In the rate design for Option G, customers were to be exposed to the variation in the hourly pool price as an incentive to be responsive to the hourly price, while at the same time making them approximately revenue neutral (on a forecast basis) to the fixed price rate through the GAC, absent any response to pool price, and based on average pool price for the month. The Option G rate design specifically provided the incentive to curtail load.
The GAC was calculated based on the annual load characteristics of Rate 790 for the months of January and February 2000. Following the implementation of restructured rates effective March 1, 2000, the GAC was calculated on the basis of actual 1998 billing determinants and load characteristics of Rates 6300 and 6400. The following table sets out those actual annual load characteristics of Rates 6300 and 6400:
Table 1: Actual Annual Load Characteristics Rates 6300 and 640082
1998 Rate 6300 Rate 6400 Combined Max Demand Not Available Not Available Not Available Contract Demand (MW) 422,147 1,381,286 1,803,434 Energy (MWh) 2,742,500 10,037,000 12,779,500 Contract Demand (CD) Load 74.0% 82.7% 80.7% Factor Firm Energy Rate incl. H-factor $27.67/MWh $26.15/MWh $26.48/MWh Firm Energy Rate excl H-factor $34.37/MWh $32.85/MWh $33.18/MWh
2000 Rate 6300 Rate 6400 Combined Max Demand (MW) 378,170 1,155,670 1,533,840 Contract Demand (MW) Not Available Not Available Not Available Energy (MWh) 2,734,500 8,935,700 11,670,200 CD Load Factor Not Available Not Available Not Available
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The Board considers it important to note that Option G was only available to customers billed on Rates 6200, 6300 or 6400. Option G load, therefore, was layered on top of the base load of customers taking service under Rates 6200, 6300 or 6400. This allowed Option G customers to interrupt a portion of their load in response to high pool prices.83
The GAC rate was expressed in terms of $/kW of contract demand per month and was based on the load characteristics of the base load. As the table above illustrates, the GAC rates were based on a combined contract demand (CD) load factor of 80.7%. Using this example, the GAC rate translates to an energy credit that brought the cost of pool purchases back to the $33.18/MWh when the CD load factor is equal to approximately 81%. With this energy credit, the Option G
82 Ref. Exhibit 323 83 The Board has no knowledge of any customers on Rate 6200 that were taking Option G service.
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loads would be approximately revenue neutral compared with the base load. However, if the actual Option G CD load factor exceeds 81%, the credit expressed on energy falls short of the required energy credit. Similarly, when the CD load factor is less than 81%, the credit expressed on energy will exceed the energy credit required to achieve revenue neutrality.
In the Board’s view, the fact that GAC credits were intended to keep the Option G load revenue neutral to the revenues that would have been realized at firm load rates should be recognized in an after-the-fact allocation based on 2000 actual circumstances. In the Board’s further view, the cost-based allocation methodology determined in this Decision does so. The credits were not intended to provide a windfall to Option G load such that the effective rate provided to Option G was far below the firm load rate level. The following table sets out the load characteristics of Option G during the period January 1, 2000 to August 31, 2000:
Table 2: Option G Load Characteristics (Jan. 1 – Aug. 31/2000)84 2000 Option G Max Demand (MW) 252,259 Contract Demand (MW) 380,581 Energy (MWh) 1,159,518 CD Load Factor 52.0% Average Pool Price $85.87/MWh Less Average Credit Received $70.02/MWh Net Purchase Cost $15.85/MWh
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The Board concludes that the credit required to keep the actual Option G load revenue neutral to the base load was only $52.69/MWh. This would indicate that the Option G credits of $70.02/MWh were excessive by $17.33/MWh (See Appendix 4).
However, the Board notes that the Option G load has a significantly lower CD Load Factor than the base 6300 and 6400 loads, which the Board considers to be strong evidence that the Option G load did curtail during peak hours to the benefit of all customers on the system.
In fairness, the Board considers that it should deem that some portion of the excessive Option G credits of $17.33/MWh might have influenced the consumption decisions of Option G customers. Consequently, the Board considers it appropriate to deem some of these additional costs as a system cost that was required as a necessary incentive to change the load characteristics of the Option G portion of the customers’ Rate 6300 and 6400 load in a manner that benefited all customers, including Option G customers. In Appendix 4, the Board has calculated this benefit to be $20.09 million.85 The recognition of a system benefit, as a credit to Option G, decreases the portion of the PPDA assigned by the cost-based allocator to Option G
84 Ref Exhibit 323 85 In the Board’s view, it would not be appropriate to deem a portion of the DAT benefits to be a system cost since the DAT rate that provided the DAT Rate Adjustment on a $/MWh basis was not designed to provide a benefit to DAT customers for load curtailment.
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customers and increases the portion of the PPDA assigned to classes other than Option G as Appendix 2 indicates86.
In the absence of clear evidence establishing a system saving of this magnitude, the Board recognizes that deeming the entire $20.09 million as a system benefit may be excessive. Further, the Board has already indicated its view that there is no obligation to fairly share any incidental benefits that arise from customer consumption choices, even if they could be quantified. However, the Board also considers that it would be unfair to Option G customers to require them to effectively repay all of the credits for interruption that they did receive and which may have influenced their consumption decisions.
The Board notes that Option G customers will pay the bulk of the deferral account deficiency allocated to DAT customers since they constitute the bulk of the DAT load. However, the Board also notes that the $5.245 million adjustment at pages 37 and 40 of Decision 2001-9387 has resulted in the UNCA PPDA balance increasing from $428.454 million to $433.699 million. In the Board’s view, since that adjustment arises primarily from the variance in revenues from Option G customers, it could be assigned directly to Option G customers. This adjustment to the PPDA balance is more fully considered in Section 4.5.
On balance, after weighing all of the special circumstances of the Option G customers, the Board concludes that deeming the entire $20.09 million as a system benefit and sharing UNCA’s DAT and Option G revenue variance would be fair to all customer classes. The Board notes that, according to Appendix 2, this reduces the actual pool purchase collection shortfall by the same amount and lowers the net collection shortfall allocated to Option G customers by $17.94 million.88
The Board considers that this adjustment puts Option G on the same footing as other customer classes in that all customer classes, including Option G, will be required to pay their fair share of the pool purchase costs including the cost of the system benefits and pool price revenue variance incurred by the DISCO above the level of customer rates.
4.4 Fairness Considerations (DAT) In Decision 2000-52 dated July 27, 2000, the Board noted that any collection of the deficiency in UNCA’s deferral accounts would be done on an interim, refundable basis and that the final accounting of the distribution deferral accounts would take place in 2001:
The Board notes Encore’s submission that any interim rider should not be applied to the DAT rate classes 6820, 6830 and 6840. The Board also notes that TransAlta confirmed that it agrees that there is merit to the argument that the DAT customers are only partially hedged, reflecting the fact that the DISCO itself is only partially hedged. TransAlta submitted that since the DAT customers have
86 Line 20, Sheet: UNCA PPDA Allocation 87 2001-93 determined UNCA and AE DISCO Deferral Account Balances – PPDA 88 The Board, in Appendix 4, has also calculated that the effective Option G average energy purchase cost less the GAC rate adjustment is approximately $16-18/MWh, which agrees with the Board’s calculation in Appendix 2.
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been exposed to the pool price for the unhedged portion, these customers have not been responsible for the deficit in the pool price deferral account. It is the exposure of the fixed rate price customers on the unhedged portion, which has contributed to the deficit in the pool price deferral account. As a result, the Board notes that TransAlta has agreed with Encore that the deferral rider should not apply to the DAT. TransAlta presented a caveat to this conclusion, that being that customers currently on fixed price rates should not be allowed to escape the deferral rider by switching to the DAT.
The Board generally agrees with the position of Encore and TransAlta. The Board considers that the DAT rate provides a shield for DAT customers on the hedged portion of their load from the average pool price increase through the monthly pool price adjustment. Consequently, DAT customers have received a legislated benefit to the same extent as other rate classes. Similarly, however, DAT customers since January 1, 2000 have been exposed to the pool price on the unhedged portion of their load and have not contributed to the TransAlta DISCO deferral account deficiency.
Accordingly, the Board considers it would be desirable that any interim rider(s) approved by the Board should not apply to customers who have been in the DAT rate classes 6820, 6830 and 6840 since January 1, 2000 and, in this regard, agrees with TransAlta. At the same time, the Board agrees that fixed price rate customers should not be allowed to avoid the rider(s) by switching to the DAT. The Board is prepared to exempt DAT rate classes from the rider for the deferral account…89
Considering the interim nature of Decision 2000-52, the Board is of the view that its findings that it was “prepared to exempt DAT rate classes from the rider for the deferral account” related only to the interim rider approved in that Decision. For the reasons set out earlier in this Decision, the Board concludes that the DAT customers should be allocated a portion of both UNCA’s and AE’s deferral accounts. The final deferral account riders will take into account that UNCA’s other customers paid interim deferral account rider amounts, while DAT customers did not.90
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4.5 Fairness of the Allocation of DAT and Option G UNCA PPDA Adjustment As noted in the previous section, at pages 37 and 40 of Decision 2001-93, the Board agreed with UNCA that the net DISCO PPDA should be adjusted for Option G and DAT, to ensure that UNCA DISCO received the credits arising from differences between actual and forecast pool purchase revenues and also the costs that UNCA DISCO incurred that arose from differences between actual rate credits paid by UNCA at actual PPA/GAC Rates and rate credits forecast to be paid at forecast PPA/GAC Rates. UNCA had proposed a net cost or increase of $19.239
89 Decision 2000-52 TransAlta Interim Settlement of 2000 Distribution Deferral Account Part A: Initial Board Determinations, page 19 90 The Board, in Appendix 4, has calculated that the effective UNCA DAT average energy purchase cost less the DAT rate adjustment is approximately $55/MWh, which agrees with the Board’s calculation in Appendix 2.
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million for the Option G adjustment and a net credit or decrease of $13.993 million for the DAT Adjustment resulting in an overall net increase to UNCA’s PPDA of $5.245 million. This resulted in the UNCA PPDA balance increasing from $428.454 million to $433.699 million.
In Decision 2001-93, the Board recognized that the intent of the UNCA PPDA was to protect UNCA from all variances caused by pool price changes, including revenue variances arising from rates affected by the pool price. Both the PPA credit and GAC credit rates are affected by changes in pool price. Accordingly, the Board accepted UNCA’s net PPDA adjustment of $5.245 million.
The Board notes that UNCA provided a forecast of the credit/charge from the PPA component of the DAT rate and the GAC component of the Option G rate using a PPA and GAC rate that was developed from the 2000 forecast of pool prices.91 The PPA and GAC rate developed from the 2000 pool price forecast was applied to actual PPA and GAC volumes to calculate a forecast credit of $0.19 million for the PPA credit and a forecast charge of $6.38 million for the GAC. UNCA then calculated the actual PPA credit and actual net GAC credit of $73.24 million and $81.18 million respectively using actual 2000 pool prices and actual volumes. The DAT/Option G total revenue variance was then calculated using the pool purchase revenue variance and the PPA/GAC revenue variance resulting in a DAT $13.929 million credit and Option G $19.239 million charge respectively.
The Board accepted the PPA and GAC forecast on the basis that UNCA (or its predecessor TransAlta) would have included a forecast of PPA and GAC revenues (based on forecast volumes) in the determination of the 2000 rate reduction rider in the proceeding leading to Decision 2000-31. This forecast revenue from DAT and Option G would have formed part of the forecast for all rate classes required to meet the 2000 forecast revenue requirement. From the record of that proceeding, the Board notes that Column E of Schedule 6 from TransAlta’s Application shows that a forecast revenue revision was included “due to reinstatement of the Generation Access Credit” or GAC.
The Board considers it important to verify the PPA and GAC credit/charge forecasts in the context of the forecasts for all rate classes. Accordingly, the Board directs UNCA, in its April 29, 2002 refiling, to provide a schedule that sets out the generation revenue forecast by rate component from each rate class, reconciled to the Board-approved 2000 revenue requirement, including the date(s) when the forecasts were made.
The Board considers that the Option G and DAT revenue variance adjustment could have been assigned to rate class on a causation basis. However, the Board notes that there were no other similar pool price variances for other rate classes since for all other rate classes none of the energy rate components varied with pool price.
The Board, in a previous section of this Decision noted the special circumstances of Option G customers and also notes the fact that the revenue variances of Option G and DAT customers were not specifically referred to as being part of the UNCA PPDA formula. The Board is not
91 UNCA provided a forecast of the credit/charge to be paid/received to/from DAT customers and Option G customers in Exhibit 312 BR-19 Schedule 2.3
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persuaded that Option G and DAT customers would have necessarily been aware of the Board’s intent that revenue variances could also be included in the PPDA For these reasons the Board considers that it would be unfair for Option G and DAT customers to bear the entire cost or receive the entire benefits of the revenue variance.
The Board also considers that DAT customers with a positive revenue variance are not significantly discriminated against if the revenue variances were not assigned to rate classes on a causation basis since most of the revenue variance for DAT customers occurred in the final four months of 2000 when the former Option G customers constituted the majority of the DAT customers.
Accordingly, the Board concludes that the adjusted UNCA PPDA balance of $433.699 million should be allocated to all customer classes, including Option G and DAT, using the same cost- based allocator that would have been used for allocation of the unadjusted balance of $428.454 million.
4.6 Board Conclusions After testing the implications and fairness of the allocation methodology determined in section 3 of this Decision, the Board is satisfied that this Decision provides a cost-based allocation to customers of the net DISCO PPDAs that requires no further adjustment for fairness considerations save for the Option G system benefit fairness adjustment determined in this section.
Accordingly, hereby the Board approves the PPDA allocation methodology set out in section 3 of this Decision, as adjusted for the Option G system benefits as illustrated on the Appendix 2 template.
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5 ALLOCATION TO RATE CLASSES OF GENCO COMPONENTS PASSED THROUGH TO DISCOS
5.1 Introduction There were a number of GENCO components that represented either charges or credits to the DISCOs. In this section the Board will consider how those charges or credits should be allocated to customer classes as components of the DISCO PPDAs.
IPCCAA submitted that the GENCO components passed through to the DISCOs could fit into the following categories:
• GENCO deferral account related to generation and ancillary services (dollar amounts available on an hourly basis) • GENCO deferral amounts related to ATCO ancillary services (dollar amounts available only on a monthly basis) • GENCO STS claims
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• Miscellaneous GENCO amounts (Reservation Price adjustments for transmission interconnection, EAL Rider B refunds, and miscellaneous smaller amounts).
For UNCA, the amounts of each of these components are set out below:
Table 3: GENCO Components Passed Through to UNCA (per IPCCAA)92 (Positive values represent credits to UNCA) $ 000 GENCO Deferrals (hourly) 42,527 GENCO Deferrals (monthly) 21,466 GENCO STS (hourly) (36,122) Miscellaneous GENCO (2,860)
Amounts for AE DISCO were comparable per unit of load.
The Board will deal with these suggested categories in the following sub-sections. Illustrated in Appendix 2 is the Board determined method of allocating the amounts of GENCO components passed through to DISCOs.
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5.2 Allocation of GENCO Deferrals to DAT 5.2.1 Introduction AE DISCO and UNCA DISCO did not allocate any GENCO deferral refunds to DAT customers.
5.2.2 Views of Interested Parties Views of AE DISCO AE DISCO’s views respecting the allocation of GENCO deferrals to DAT customers is reflected in the following excerpt from the transcript:
07 Q And you focused on the costs, but of course, the GENCO deferrals, at least in two cases, are what we might call "benefits"; and I take it from your answer that those were not allocated in any part to DAT customers.
12 A MR. BECKETT: That's correct.
13 Q Why is that?
14 A MR. BECKETT: The rationale behind that is that they were on Pool price and did not participate directly in payments for generation costs. It was a flow through of Pool price. They were not treated as -- in the same manner that customers on fixed energy rates were.93
92 IPCCAA Argument page 30 93 Transcript 4953
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AE excluded DAT customers from all portions of the main DISCO deferral account allocation due to the fact that their energy consumption was based on pool price during 2000. AE considered that DAT customers have already been compensated in kind by proxy due to the fact that the DAT C-credit was designed by the Board in such a way that, in months where pool price was lower than forecast and the C-credit would otherwise have been negative, the C-credit was set at $0/MWh. Therefore, the DAT customers would not have had to pay the DISCO for any shortfall.
Views of UNCA UNCA’s views respecting the allocation of GENCO deferrals to DAT customers is reflected in the following excerpt from the transcript:
Q But unlike the deferral account calculation, there is nothing in the direct-access tariff by which any benefit of the GENCO deferral accounts is passed through to the DAT customers, correct?
A MR. STROH: Correct.
Q And what is the justification for the disparity of treatment?
A MS. KIRRMAIER: Well, one reason, I guess, in the treatment that you are referring to, I assume, is the fact that we are allocating none of the deferral account, be it a positive or negative component, to the direct-access tariff. And one reason behind that, and it might not be a complete reason, but it was a previous Board decision that DAT customers do not get allocated a portion of the deferral account. Now, the question is whether the deferral account still looks the same way as it was thought to look at the time that decision was put out.
Q Which decision is it that you have in mind, Ms. Kirrmaier?
A MS. KIRRMAIER: It is either 2000-52 or 2000-60. And we are thinking -
Q You are talking about either or both of the decisions that arose from the TransAlta application for interim rate rider.
A MS. KIRRMAIER: Yes. That's right.
Q So, you said it might not be a complete reason. Can you think of any other reasons? And you are quite correct. I should have said -- defined what I meant by "disparity of treatment." You are quite correct. There is none of the GENCO deferral account balances being allocated to DAT customers whether positive or negative. But I am trying to get on the table all the reasons why there is a difference in treatment.
A MS. KIRRMAIER: So, I hope I remember the question after all that. So, I think all the intent behind what we proposed was that back to my earlier explanation of the way we thought of DAT was that consumers on that rate
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received similar treatment in the way I described earlier to what the DISCOs received in realtime during those months that they were consuming energy on the DAT. And I don't think there is a whole lot more we can add to that.94
Views of IPCCAA IPCCAA noted that the DAT passed through Pool Price and a share of UOV refunds. IPCCAA submitted that was logical therefore to exclude them from allocation of the Pool Price and UOV related deferral account components. In fact, IPCCAA submitted that there appeared to be consensus that DAT loads should not bear a portion of the pool purchase or UOV components of the deferral accounts. However, there was no basis for excluding DAT from other deferral amounts that were not passed through in the DAT. IPCCAA stated that neither AE nor UNCA establish any logical basis for excluding DAT load from receiving an allocation of the GENCO deferrals (which are in some cases benefits and in other instances costs).
IPCCAA noted that as the majority of the DAT load consisted of load that was Option G for the first 8 months of the year and DAT for the last 4 months, an annual allocation of GENCO deferral amounts would not introduce any double allocation of these balances to DAT customers.
IPCCAA emphasized that the DAT loads were subject to certain GENCO related deferrals; both AE95 and UNCA96 confirmed that DAT loads received reduced UOV related adjustments in the months of October through December 2000 because actual UOV refunds were used to calculate the PPA credits (UNCA) and the C-credit (AE). The actual UOV credits in October through December reflected the TSR-related interim suspension of the Wabamun 4 UOVs. IPCCAA submitted that it would be inconsistent to find that DAT loads were responsible for the GENCO- related costs (for a potential Wabamun TSR claim) and yet not allow the DAT loads to obtain a share of the GENCO positive deferral balances.
IPCCAA responded to UNCA’s position at pages 34-35 of its Argument.
5.2.3 Views of the Board - Allocation of GENCO Deferrals to DAT Customers In the case of both AE DISCO and UNCA DISCO, DAT customers were not explicitly excluded from the DISCO PPDA allocation. Earlier in this Decision the Board has found that the DAT customers should be included in the allocation of, and should pay a fair portion of the DISCO PPDAs.
Under the EU Act, all users of electricity have a right to a fair allocation of the benefits and costs of the legislated hedges. Many of the GENCO deferral accounts relate to the reservation payments which are the “costs” side of the legislated hedges. Therefore, under these circumstances, the Board considers that DAT customers should also be allocated a portion of all of the GENCO deferral accounts.
94 Transcript, pages 4550-4552 95 Transcript, page 4956 96 Transcript, page 4572
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Accordingly, the Board directs AE DISCO to allocate any GENCO or ancillary service deferral balances to DAT customers on the same basis used for other customer classes (i.e. annual class energy use).
Similarly, the Board directs UNCA to allocate any GENCO or ancillary service deferral balances to DAT customers on the same basis used for other customer classes (i.e. annual class energy use).
For the reasons provided earlier in the Decision the Board considers that customers served under negotiated rates (UNCA Rate 6600 Temporary Energy Service, UNCA Rate 6700 Real Time Pricing and AE Rate Pool Opportunity Rate Price Schedule 33) should not have the overall rate level payable under those rates effectively changed in an after-the-fact allocation of the DISCO deferral accounts. Accordingly, they will not be allocated any of the GENCO deferral amounts.
In the Board’s view, this approach provides a fair allocation of the actual benefits and costs of the legislated hedges to existing and new customers as required by the EU Act given the implementation of deferral accounts for year 2000.
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5.3 GENCO Generation and Ancillary Service Deferrals 5.3.1 Views of Interested Parties Views of AE and UNCA AE and UNCA treated the GENCO and ancillary service deferrals as an offset to the net DISCO deferral account.
Views of IPCCAA IPCCAA submitted that all three GENCOs had deferral accounts that passed through to customers most, if not all, of the pool price risks related to output, as well as most, if not all, volume risk (with the exception of EGI if the Board were to retain the 50/50 sharing for the gas- fired units). In IPCCAA’s view, this effectively put unit performance risk with the customers. If the generator availability were above forecast, the customers would generally see a positive balance, to be refunded to the deferral accounts (amounts may accumulate either through a generation deferral account or through the ancillary service deferral account).
IPCCAA submitted that the effect of allocating the GENCO deferrals on an hourly or monthly basis was to effectively alter the nature of the entitlements. Through such allocations, the amount of the hedge received in any hour (or month) depends upon the performance of the regulated generating units on line during that period. IPCCAA stated that this effect could be described as altering the legislated hedges from financial hedges to unit-contingent hedges - i.e. the availability of the hedges is contingent upon the availability of the physical generating units notionally underlying the hedges.
IPCCAA provided the following table summarizing the allocation of UNCA’s GENCO deferral amounts available on an hourly basis on an annual, monthly and hourly basis.
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Table 4: Allocation of GENCO Deferrals to UNCA Rate Class (per IPCCAA)97 (Excludes ATCO Ancillary Service) GENCO GENCO GENCO Rate Class Rate Annual Monthly Hourly Description Code $/MWh $/MWh $/MWh Residential 11XX–12XX (1.8) (2.1) (2.0) UNCA Farm 21XX–23XX (1.8) (2.0) (1.9) REA Farm 24XX–25XX (1.8) (2.0) (2.0) UNCA Irrigation 26XX–27XX (1.8) (0.8) (0.9) REA Irrigation 28XX–29XX (1.8) (0.5) (0.6) Exterior Lighting 3XXX (1.8) (2.4) (3.0) Small General Service 41XX–43XX (1.8) (1.9) (1.8) Pumping 44XX–46XX (1.8) (1.8) (1.8) General Service 61XX–62XX (1.8) (1.8) (1.8) Large General Time-of-Use 63XX (1.8) (1.8) (1.8) Direct Connected Service 65XX (1.8) (1.7) (1.7) Direct Access Tariff 68XX (1.8) (4.5) (4.5) Option G Option G (1.8) (0.2) (0.3) Wholesale Service (Closed) 81XX (1.8) (1.9) (1.9) Total UNCA — (1.8) (1.8) (1.8)
Source: Exhibit 914 Tab: 1 Comparison divided by Schedule 8-G Energy.
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IPCCAA noted that the ATCO ancillary service component of the GENCO deferrals was significant (roughly 1/3 of the total GENCO refunds) but could not be included in the comparison table above because it cannot be allocated on an hourly basis, as the information simply was not available. IPCCAA submitted that the arguments supporting the annual, rather than monthly or hourly, allocation of the other GENCO deferral amounts apply equally well to the ATCO ancillary service deferral.
IPCCAA submitted that a monthly allocation would effectively reduce the hedge that was available to load during the period on unit turn-arounds.
In IPCCAA’s view, by looking at the combined GENCO deferral account balances, the “availability” of the units (as well as the interaction of the availability with Pool Price), over the course of the year, could be seen. IPCCAA noted that the figure below showed UNCA’s share of the aggregate GENCO deferral balances demonstrating that the GENCO deferral accumulations varied considerably over the months.
97 IPCCAA Argument page 32
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Table 5: Graph Showing UNCA Share of 2000 GENCO Deferral (Per IPCCAA)98
UNCA Share of Genco Deferral by Month Generation plus Ancillary Services
h 40 30 20 10 0 -10 -20 $ million per mont Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Month
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IPCCAA submitted that the monthly allocation would unfairly allocate more GENCO surplus to rate classes with the highest relative loads in December (the month of the greatest positive deferral contribution) and penalize those with the smallest relative loads in December. Residential and Streetlights are examples of the former and Irrigation of the latter. IPCCAA also submitted that, while the DAT unit amount appeared to be large ($(4.5)/MWh), it should be viewed in terms of the entire year. At most, DAT load was Option G for 8 months and DAT for 4 months. Therefore, the appropriate unit value to compare for the hourly allocation would be $(1.7)/MWh (calculated as 4/12 x 4.5 + 8/12 x 0.3).
IPCCAA submitted that the hourly allocation would unfairly reduce the hedge available to Option G and DAT customers. On an hourly basis, given that the deferrals were on average positive, IPCCAA stated that one would expect there to be larger deferrals at times of high pool price. As Option G and DAT reduced load at times of high pool prices, IPCCAA stated that the hourly allocation would unfairly reduce the hedge available to them. IPCCAA submitted that those loads were supposed to react to pool price. IPCCAA stated that an hourly deferral account allocation would suggest that these loads should have been reacting to a combination of pool price and a measure of what generating units were on or off-line.
In IPCCAA’s view, such a fundamental change (reinterpreting the entitlements as unit- contingent hedges) should only be undertaken if the Board is convinced that customers would have contemplated this understanding at the time the deferral accounts were created. IPCCAA submitted that such a reinterpretation was not warranted and, therefore, recommended an annual allocation of these GENCO deferral amounts.
Views of Other Interested Parties No other parties took a position on this issue.
98 IPCCAA Argument, page 33.
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5.3.2 Views of the Board - GENCO Generation and Ancillary Service Deferrals The Board notes that the forecast GENCO deferral and ancillary service deferral components were included in the forecast Reservation Price. Therefore, the Board considers that the actual GENCO and ancillary deferrals should also be treated as Reservation Price-related.
The Board also notes that forecast Reservation Payments (RP) were spread equally over annual DISCO energy use in the original rate design such that each rate class received the same cost per MWh. Finally, the Board notes that the RP was incurred by the DISCO, based essentially on its total forecast annual load.
In Decision 2001-83, the Board indicated that:
The Board has reviewed AE’s proposed allocation method for reservation payment deferrals and considers the allocation to rate class on the basis of annual energy consumption to be reasonable. However, the Board will discuss AE’s use of forecast consumption below.
The Board notes that none of the Intervenors, other than IPCCAA, took exception to an allocation based on annual energy consumption. IPCCAA suggested that the allocation should be done on the basis of monthly energy consumption.
The Board notes that forecast reservation payments were allocated to rate class on the basis of annual energy consumption. Accordingly, the Board is not persuaded that it should deviate from an annual allocator.
However, the Board notes that 2000 actual energy consumption influenced many of the Reservation Payment adjustments. Accordingly, the Board considers that Reservation Payment adjustments should be allocated to rate class on the basis of year 2000 actual annual class energy consumption, rather than AE’s proposed forecast consumption allocation.
The Board directs AE to allocate, in its refiling, reservation payment deferrals to rate class on the basis of actual 2000 annual class energy consumption, rather than AE’s proposed forecast consumption allocation.99
The Board similarly considers that actual 2000 annual class energy consumption should be used for GENCO deferrals that are related to Reservation Price. In the Board’s view, it would be fair for customer classes to see the reduction in Reservation Price on the basis of actual annual load. Therefore, the Board is not persuaded that it should deviate from the method approved for allocation of the RP on the basis of annual load for the reduction in RP. Accordingly, the Board approves the allocation of GENCO deferrals and ancillary service deferrals on the basis of actual annual class energy use.
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99 Decision 2001-83, pages 23-24
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5.4 GENCO STS Claims 5.4.1 Introduction The DISCOs proposed a pass-through of claims from the GENCOs reflecting the additional costs incurred by the introduction of Supply Transmission Service (STS) charges on June 1, 2000.
TransAlta GENCO STS Charges The forecast STS (utilizing forecast Pool Price for the ancillary service component) was incorporated into all unit UOPs by TransAlta GENCO. TransAlta GENCO charges to the DISCOs were intended to recover the difference between the actual and forecast STS component of the UOP.
AE GENCO STS Charges AE GENCO did not incorporate the STS into unit UOPs. Instead AE GENCO’s recovery of forecast STS charges was addressed in Decision 2000-81 and passed on to the DISCOs as a Reservation Payment adjustment. AE GENCO applied for a true-up of the STS charge in its GENCO Other Matters Application.
EGI STS Charges EGI incorporated the actual STS (utilizing actual Pool Price for the ancillary service component) into all unit UOPs. In the Power Pool settlement, the difference between Pool Price and UOP incorporating actual STS was refunded to the DISCOs. Accordingly, EGI made no additional STS claim in these proceedings. However, EGI separately identified the STS component of the surplus/shortfall that was included in the EGI pool price deferral account.
Views of UNCA In these proceedings, UNCA sought to recover its share of the TransAlta STS claim as well as its share of the AE GENCO STS claim from Decision 2000-81.
Views of AE DISCO AE DISCO sought to recover its share of the TransAlta STS claim though these proceedings although it claimed its share of the AE GENCO STS claims from Decision 2000-81 in its GENCO Other Matters application.
Views of IPCCAA UNCA has incorporated the TransAlta and ATCO STS claims as part of the reservation price allocation. Their approach to doing so should, effectively, be a monthly allocation although it is not clear whether UNCA has attributed the amounts to the months in which the charges were incurred as opposed to the months in which UNCA was billed.100
In the allocation of the STS claims, IPCCAA stated that it should be recognized that the GENCO STS charges were a variable cost imposed upon the generators effective June 1, 2001. As a
100 Transcript page 4539
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variable cost, STS charges would appropriately be considered a component of the unit’s UOP. In fact, the Board approved actual STS charges as a component of EGI unit UOPs in Decision 2000-5.
Recognizing the STS as a component of the UOP charges results in a reduction of UOV refunds in each hour and therefore it is IPCCAA’s view that TransAlta’s and ATCO’s STS costs should be recognized as a reduction in the DISCO’s UOV refunds in the allocation of the deferral accounts.
As the deferral amounts are additive this effect can be achieved through a monthly allocation of STS charges. IPCCAA noted that whereas they had proposed that DAT load not be allocated UOV deferral refunds, IPCCAA considered that STS allocations should apply to DAT as the UOV refunds paid to DAT did not reflect TransAlta’s and ATCO’s STS amounts.
IPCCAA recognized that STS allocations should apply to DAT as the UOV refunds paid to DAT did not reflect TransAlta’s and ATCO’s STS amounts even though IPCCA did not view that DAT customers should be allocated any other portions of the UOV refunds component of the deferral accounts.
5.4.2 Views of the Board - GENCO STS Claims The Board agrees with IPCCAA that the STS charges are appropriately considered as a component of the UOP charges. However, the Board notes that changes in the UOP eventually find their way into the surplus/shortfall for the GENCO deferral accounts. The Board also notes that the surplus/shortfall was deemed to be a component of the Reservation Price.
As noted above, the Board considers that the actual GENCO deferrals should be treated as Reservation Price related. The Board notes that forecast Reservation Payments were spread equally over annual DISCO energy use such that each rate class received the same Reservation Payment cost per MWh. The Board is not persuaded that it should deviate from the method approved on a forecast basis.
Accordingly, the Board approves the allocation of STS charges on the basis of actual annual class energy use.
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5.5 Keephills and Wabamun TSR Adjustments 5.5.1 Introduction In Table 4 (UNCA) and Table 6 (AE) of Decision 2002-024, the Board approved the Keephills and Wabamun TSR adjustment amounts that each DISCO is to recover from its customers.
5.5.2 Views of the Board - Keephills and Wabamun TSR Adjustments The Board notes that these TSR adjustment amounts are essentially a reduction in the obligations of the regulated generating plants obligations or, in other words, a reduction in the UOV refunds paid to the DISCOs.
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The intent of the hourly allocation of UOV refunds approved by the Board in this Decision, is to reduce the net variation in pool price from hour to hour. For consistency and fairness, the Board considers that the TSR adjustment amounts should also be allocated to each class on the basis of the class share of total UOV refunds.
Accordingly, in Appendix 2 the Board approves the allocation of the approved Keephills and Wabamun TSR adjustment amounts on the basis of the share of total UOV refunds allocated to each class.
5.6 Miscellaneous GENCO Amounts 5.6.1 Views of Interested Parties Views of IPCCAA IPCCAA submitted that a number of amounts had been included in the EGI, AE GENCO and TransAlta GENCO deferrals, as well as amounts introduced by UNCA DISCO and AE DISCOCO that do not relate to Pool Price, UOV refunds, GENCO generation or ancillary service deferral accounts.
For UNCA, IPCCAA identified the following miscellaneous items:
Table 6: Miscellaneous GENCO Amounts for UNCA (per IPCCAA)101 Item $ 000 Reference ATCO GENCO carrying costs 610 ATCO Schedule 1.0 EGI GENCO carrying costs and EAL Rider B (2,804) EGI, Page 9 TAU GENCO ILRAS and EAL Rider B (2,719) TAU Schedule 1 STS RP adj. per 2000-31 and 2000-32 (1,919) UNCA Schedule 1.0, Rev. 1 TAU Keephills TSR (net amount) 2,983 UNCA Schedule 1.0, Rev. 1 Shortfall in calculated ATCO STS vs. billed 989 Calculated amount less than amount billed to DISCOs. Total (2,860)
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IPCCAA included an amount representing the difference between its calculation of the AE STS claims and the amount included in UNCA’s application. IPCCAA noted that the UNCA amount includes an estimate of the December STS charges, with a true-up to follow.
IPCCAA noted that UNCA incorporated the GENCO items as part of the GENCO deferral items And, where monthly data was not available, had allocated the amounts annually. IPCCAA submitted that its recommended allocation approach for these items did not differ from UNCA’s.
IPCCAA recommended that these amounts be allocated on an annual basis to all loads (excluding temporary energy and POR).
101 IPCCAA Argument page 30
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Views of Other Interested Parties No other parties took a position on these issues.
5.6.2 Views of the Board - Miscellaneous GENCO Amounts In view of the relatively small size of the miscellaneous GENCO amounts passed through to DISCOs, the Board considers that they should not be allocated differently from the composite rate class allocation of the sum of all other GENCO components.
Accordingly, the Board directs that the miscellaneous GENCO components be allocated to rate class on the same basis as the composite of all other GENCO components that were allocated to rate class.
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6 VIEWS OF THE BOARD - ALLOCATION REFILINGS
The Board directs UNCA and AE DISCO to refile the DISCO and GENCO OMA and PPDA amounts, as approved in Decisions 2002-023 and 2002-024, allocated to rate class in accordance with the Board’s findings in this Decision and following the Board’s Allocation Template in Appendix 2. The Template illustrates the Board-approved method of allocating to customer classes the amounts of the DISCO PPDA and GENCO components passed through to DISCOs and the Board-approved method of calculating the deficiency riders on a customer class basis.
Also, the Board directs UNCA and AE DISCO to include in their refilings the allocation of GENCO harm amounts, as approved in Decision 2002-025.
The Board directs UNCA and AE DISCO to calculate and file a final rate deficiency rider, effective June 1, 2002, to recover the DISCO OMA, PPDA and GENCO Harm amounts allocated to each rate class.
The Board directs UNCA and AE DISCO to file the above information on or before April 29, 2002.
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7 SUMMARY OF KEY FINDINGS
This section is provided for the convenience of readers. The reader is cautioned, however, that a summary of this nature is open to legitimate differences of opinion as to which findings may be considered “key”. For this reason, readers should not rely on this section as a means to fully appreciate the totality of the Board’s findings in this Decision. Such an appreciation can only be obtained by reading all of the Board’s findings set out in this Decision.
In the event of any difference between the Key Findings in this section and those in the main body of the report, the wording in the main body of the Decision shall prevail.
1. In the Board’s view, the appropriate allocation of the components decreasing the net deferral account is no less important than the appropriate allocation of the components increasing the net deferral account. Therefore, in the Board’s view, appropriate application of the principle of cost causation in the circumstances requires that the PPDA components causing increases and those causing decreases should be dealt with individually, to the extent practical, to ensure that each rate class essentially pays its fair DISCO costs and receives its fair DISCO benefits...... 8 2. The Board considers that an equitable allocation of the DISCO deferral accounts based on these cost causation principles should result in all customer classes paying the same portion of the net pool purchases that they caused the DISCO to incur on their behalf. In other words, cross-subsidization between customer classes of net pool purchases should be minimized...... 8 3. For the reasons set out above, the Board concludes that only UNCA Rate 6600 Temporary Energy Service, UNCA Rate 6700 Real Time Pricing and AE Rate Pool Opportunity Rate Price Schedule 33 rate classes should be excluded from the allocation of the year 2000 DISCO deferral accounts...... 11 4. Also for these reasons (and the other reasons set out in Section 4 of this Decision dealing with Fairness Considerations), the Board concludes that all other customers should be included in the allocation of the year 2000 DISCO deferral accounts, as necessary, to reflect the fair allocation of each DISCO’s deferral account in accordance with the principles set out in this Decision...... 11 5. Having regard to the considerations expressed in assessing the methodologies proposed by AE and UNCA, the Board has concluded that a top-down allocation methodology introducing actual revenue components would result in the determination of an appropriate cost-based allocator of the net PPDA balances and would achieve a fair, cost- based allocation to customer classes...... 16 6. For all of these reasons, the Board considers that an annual or monthly allocation of the UOVs (Component 2) to fixed rate customers according to the 2000 Rate design would fall short of fairly addressing the allocation of the unexpected increase in the deferral accounts assuming pool purchases (Component 1) are also allocated hourly...... 43 7. For all of these reasons, the Board does not consider any of the fairness concerns raised by Option G customers as discussed in this section to warrant an adjustment to the cost- based allocation methodology determined by the Board in this Decision...... 53
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8. However, the Board considers Option G load to be somewhat different from the load placed on the system by other rate classes, which raises different fairness concerns. The Board will deal with this difference in the next section...... 53 9. The Board concludes that the credit required to keep the actual Option G load revenue neutral to the base load was only $52.69/MWh. This would indicate that the Option G credits of $70.02/MWh were excessive by $17.33/MWh (See Appendix 4)...... 55 10. On balance, after weighing all of the special circumstances of the Option G customers, the Board concludes that deeming the entire $20.09 million as a system benefit and sharing UNCA’s DAT and Option G revenue variance would be fair to all customer classes. The Board notes that, according to Appendix 2, this reduces the actual pool purchase collection shortfall by the same amount and lowers the net collection shortfall allocated to Option G customers by $17.94 million...... 56 11. Considering the interim nature of Decision 2000-52, the Board is of the view that its findings that it was “prepared to exempt DAT rate classes from the rider for the deferral account” related only to the interim rider approved in that Decision. For the reasons set out earlier in this Decision, the Board concludes that the DAT customers should be allocated a portion of both UNCA’s and AE’s deferral accounts. The final deferral account riders will take into account that UNCA’s other customers paid interim deferral account rider amounts, while DAT customers did not...... 57 12. The Board also considers that DAT customers with a positive revenue variance are not significantly discriminated against if the revenue variances were not assigned to rate classes on a causation basis since most of the revenue variance for DAT customers occurred in the final four months of 2000 when the former Option G customers constituted the majority of the DAT customers...... 59 13. Accordingly, the Board concludes that the adjusted UNCA PPDA balance of $433.699 million should be allocated to all customer classes, including Option G and DAT, using the same cost-based allocator that would have been used for allocation of the unadjusted balance of $428.454 million...... 59 14. Accordingly, hereby the Board approves the PPDA allocation methodology set out in section 3 of this Decision, as adjusted for the Option G system benefits as illustrated on the Appendix 2 template...... 59 15. For the reasons provided earlier in the Decision the Board considers that customers served under negotiated rates (UNCA Rate 6600 Temporary Energy Service, UNCA Rate 6700 Real Time Pricing and AE Rate Pool Opportunity Rate Price Schedule 33) should not have the overall rate level payable under those rates effectively changed in an after- the-fact allocation of the DISCO deferral accounts. Accordingly, they will not be allocated any of the GENCO deferral amounts...... 63 16. The Board similarly considers that actual 2000 annual class energy consumption should be used for GENCO deferrals that are related to Reservation Price. In the Board’s view, it would be fair for customer classes to see the reduction in Reservation Price on the basis of actual annual load. Therefore, the Board is not persuaded that it should deviate from the method approved for allocation of the RP on the basis of annual load for the reduction in RP. Accordingly, the Board approves the allocation of GENCO deferrals and ancillary
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service deferrals on the basis of actual annual class energy use...... 66 17. Accordingly, the Board approves the allocation of STS charges on the basis of actual annual class energy use...... 68 18. Accordingly, in Appendix 2 the Board approves the allocation of the approved Keephills and Wabamun TSR adjustment amounts on the basis of the share of total UOV refunds allocated to each class...... 69
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8 SUMMARY OF DIRECTIONS
This section is provided for the convenience of readers. In the event of any difference between the Directions in this section and those in the main body of the report, the wording in the main body of the Decision shall prevail.
1. Accordingly, the Board directs UNCA DISCO to use the Board’s Allocation Template in Appendix 2 and to follow the steps explained below to determine the “actual” pool purchase shortfall for each customer class: ...... 19 Step 1: Calculate DISCO hourly “actual” pool purchases by customer class using actual hourly volumes by customer class and actual pool price (this step recognizes the “actual” pool purchase costs caused by each customer class as a whole) as described in the “Actual” Class Pool Purchase Costs section earlier in this Decision. Step 2: Determine “actual” pool purchase costs already paid by each customer class through existing rates (this step recognizes the “actual” revenues − i.e. energy charges absent the allocated H-factor and other adjustments−received by the DISCO towards those pool purchase costs) as described in the “Actual” Class Pool Purchase Revenues section earlier in this Decision. Step 3: Determine the “actual” pool purchase deficiency for each customer class by subtracting the “Actual” Class Pool Purchase Revenues from the “Actual” Class Pool Purchase Costs.
2. Also, the Board directs UNCA DISCO to provide two versions of the first page of the Allocation Template as follows:...... 20 • Version 1 should allocate the annual deferral account balance per the Template using the characteristics of the entire year 2000 to determine the amounts allocated to each customer class to be used in the determination of the class riders. • Version 2 should allocate the portion of the deferral account that accrued from January 2000 through August 2000 separately from the portion of the deferral account that accrued from September 2000 through December 2000 using the characteristics of the respective periods. Version 2 should then total the amounts allocated to each customer class over each of the two periods to be used in the determination of the class riders.
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3. If there are any differences in the final amounts allocated to customer class between Version 1 and Version 2, the Board directs UNCA to explain the differences and provide UNCA’s view as to which version produces more equitable results...... 20
4. Similarly, the Board directs AE DISCO to use the Board’s Allocation Template in Appendix 2 and to follow the steps explained below to determine the “actual” pool purchase shortfall for each customer class:...... 20 Step 1: Calculate hourly forecast pool purchases by customer class using forecast hourly volumes by customer class and actual pool price (this step recognizes the “actual” pool purchase costs caused by each customer class in relation to its forecast consumption) as described in the “actual” Class Pool Purchase Costs section earlier in this Decision. Step 2: Determine forecast pool purchase costs already paid by each customer class through existing rates (this step recognizes the revenues−i.e. energy charges absent the allocated H-factor and other adjustments−forecast to be received by the DISCO towards those forecast pool purchase costs) as described in the “Actual” Class Pool Purchase Revenues section earlier in this Decision. Step 3: Determine the forecast pool purchase deficiency based on forecast energy use for each customer class by subtracting the “Actual” Class Pool Purchase Revenues from the “Actual” Class Pool Purchase Costs.
5. Accordingly, the Board directs UNCA and AE to use the Board’s Allocation Template (Appendix 2) and to follow the steps explained below to determine the actual outstanding UOV refund due to each customer class: ...... 24 Step 1: Allocate actual UOV refunds to customer class using actual hourly volumes by customer class (this step reduces the hourly unit price of the customer class’s pool purchases to the same net unit price paid by the DISCO). Step 2: Determine actual UOV refunds already received by customer class through the UOV refund (entitlement) portion of the H-factor (this step recognizes the credits already paid by the DISCO to customers through the rates). Step 3: Determine the outstanding UOV refunds due to each customer class.
6. The Board directs UNCA DISCO to follow the steps explained below to allocate UNCA’s net PPDA deficiency (i.e. the difference between Component 1 and Component 2): ...... 24 Step 1: Determine the preliminary customer class deficiency by calculating the difference between the amount of the “actual” pool purchase shortfall (i.e. Component 1) and the actual outstanding UOV refunds (i.e. Component 2) for each customer class. Step 2: Determine the final customer class deficiency by allocating the final, cost- based (i.e. actual) net DISCO PPDA deficiency to each customer class in accordance with that class’s share of the total of all the preliminary customer class deficiencies.
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7. The Board directs AE DISCO to follow the steps explained below to allocate AE’s net DISCO PPDA deficiency (i.e. the difference between Component 1 and Component 2): ... 25 Step 1: Determine the preliminary customer class deficiency by calculating the difference between the amount of the forecast pool purchase shortfall (i.e. Component 1) and the actual outstanding UOV refunds (i.e. Component 2) for each customer class. Step 2: Determine the final customer class deficiency by allocating the final, cost- based (i.e actual) net DISCO PPDA deficiency to each customer class in accordance with that class’s share of the total of all the preliminary customer class deficiencies.
8. The Board considers it important to verify the PPA and GAC credit/charge forecasts in the context of the forecasts for all rate classes. Accordingly, the Board directs UNCA, in its April 29, 2002 refiling, to provide a schedule that sets out the generation revenue forecast by rate component from each rate class, reconciled to the Board-approved 2000 revenue requirement, including the date(s) when the forecasts were made...... 58
9. Accordingly, the Board directs AE DISCO to allocate any GENCO or ancillary service deferral balances to DAT customers on the same basis used for other customer classes (i.e. annual class energy use)...... 63
10. Similarly, the Board directs UNCA to allocate any GENCO or ancillary service deferral balances to DAT customers on the same basis used for other customer classes (i.e. annual class energy use)...... 63
11. Accordingly, the Board directs that the miscellaneous GENCO components be allocated to rate class on the same basis as the composite of all other GENCO components that were allocated to rate class...... 70
12. The Board directs UNCA and AE DISCO to refile the DISCO and GENCO OMA and PPDA amounts, as approved in Decisions 2002-023 and 2002-024, allocated to rate class in accordance with the Board’s findings in this Decision and following the Board’s Allocation Template in Appendix 2. The Template illustrates the Board-approved method of allocating to customer classes the amounts of the DISCO PPDA and GENCO components passed through to DISCOs and the Board-approved method of calculating the deficiency riders on a customer class basis...... 70
13. Also, the Board directs UNCA and AE DISCO to include in their refilings the allocation of GENCO harm amounts, as approved in Decision 2002-025...... 70
14. The Board directs UNCA and AE DISCO to calculate and file a final rate deficiency rider, effective June 1, 2002, to recover the DISCO OMA, PPDA and GENCO Harm amounts allocated to each rate class...... 70
15. The Board directs UNCA and AE DISCO to file the above information on or before April 29, 2002...... 70
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DATED in Calgary, Alberta on April 18, 2002.
ALBERTA ENERGY AND UTILITIES BOARD
(Original signed by)
N. W. MacDonald, P. Eng. Presiding Member
(Original signed by)
A. J. Berg, P. Eng. Member
(Original signed by)
R. G. Lock, P. Eng. Member
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PART R: AE DISCO & UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Deferral Accounts Proceeding
APPENDIX 1 - RELEVANT DECISIONS - 2000 DEFERRAL ACCOUNTS The following list of other relevant Decisions is provided for the convenience of readers and includes hyperlinks to those decisions on the EUB website. In some cases, the Decision may have been assigned a Decision number but may not have been issued yet.
Table 7: List of 2000 Deferral Account Related Decisions Issue Date Decision Part Applicant Decision Name Number May 10 1999 U99046 AE 1999/2000 Electric Tariff Applications – Negotiated Settlement Nov. 25, 1999 U99099 AE 1999/2000 Electric Tariff Applications EPCOR TransAlta Jan. 8, 2000 Letter IL “General Policy for Payment of Interest” 2000-1 Feb. 1, 2000 2000-2 AE 1999/2000 Electric Tariff Application Refiling Feb. 1, 2000 2000-3 TransAlta 1999/2000 Electric Tariff Application Refiling Feb. 1, 2000 2000-4 ETI 1999/2000 Electric Tariff Application Refiling Feb. 1, 2000 2000-5 EPGI 1999/2000 Electric Tariff Application Refiling May 30, 2000 2000-31 TransAlta Closure of 1999 Generation Deferral Accounts, Adj. Interest Refund Rider, 2000 Rate Reduction Rider and changes resulting from ESBI July 27, 2000 2000-52 A TransAlta Interim Settlement of 2000 Distribution Deferral Account Part A: Initial Board Determinations Aug. 31, 2000 2000-60 B TransAlta Interim Settlement of 2000 Deferral Accounts Part B: Interim Board Determination Oct. 31, 2000 2000-65 AE 2001/2002 Transmission Facility Owner (TFO) Negotiated Settlement Nov. 14, 2000 2000-69 C TransAlta Interim Settlement of 2000 Deferral Accounts Part C: Board Determination Regarding GENCO Interim Payments ordered in Decision 2000-60 Dec. 19, 2000 2000-78 D TransAlta Interim Settlement of 2000 Deferral Accounts Part D: Rescission of Interim Rate Riders Ordered in Decision 2000-60 effective January 1, 2001
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Issue Date Decision Part Applicant Decision Name Number Jan. 30, 2001 2001-7 A UNCA Part A: Interim Approval of 2001 DISCO Financing Costs for the 2000 Distribution Pool Price Deferral Account Feb. 6, 2001 2001-8 A AE DISCO Part A: Interim Approval of 2001 Financing Costs for certain 2000 Distribution Deferral Accounts Feb. 9, 2001 2001-10 A EDI Part A: Interim Approval of 2001 Financing Costs for the 2000 Distribution Pool Price Deferral Account Feb. 28, 2001 2001-12 A ENMAX Part A: Interim Approval of 2001 Financing Costs for the 2000 Distribution Pool Price Deferral Account Apr. 24, 2001 2001-26 A Red Deer Part A: Interim Approval of 2001 Financing Costs for the 2000 Distribution Pool Price Deferral Account Apr. 24, 2001 2001-27 A Lethbridge The City of Lethbridge Part A: Interim Approval of 2001 Financing Costs for the 2000 Distribution Pool Price Deferral Account May 15, 2001 2001-36 B AE Part B: Interim Supplementary Approval of 2001 Financing Costs for the 2000 Distribution Deferral Account May 25, 2001 2001-45 E IPCCAA Part E: IPCCAA Applications for review and Variance Aug. 8, 2001 2001-70 F ALL Interim Disposition of GENCO Deferral GENCOs Account Balances Nov. 9, 2001 2001-82 A GENCOs 2000 GENCO Outstanding Matters AE, TAU, Deferral Accounts (Non Pool Price) EGI Nov. 8, 2001 2001-83 B DISCOs 2000 DISCO Outstanding Matters AE UNCA Deferral Accounts (Non Pool Price) Dec. 11, 2001 2001-83 AE DISCO Addendum to 2000 DISCO Outstanding Addendum Matters Deferral Accounts (Non Pool Price) Dec. 4, 2001 2001-88 G ENMAX Review of ENMAX DISCO 2000 Pool Price Deferral Accounts Dec. 4, 2001 2001-89 H EDI Review of EDI DISCO 2000 Pool Price Deferral Accounts Dec. 4, 2001 2001-90 I Red Deer Review of Red Deer DISCO 2000 Pool Price Deferral Accounts Dec. 4, 2001 2001-91 J Lethbridge Review of Lethbridge DISCO 2000 Pool Price Deferral Accounts
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Issue Date Decision Part Applicant Decision Name Number Dec. 11, 2001 2001-92 K ALL 6 DISCO 2000 Pool Price Deferral DISCOs Accounts - Carrying Costs, Collection and Hedging Dec. 22, 2001 2001-93 L AE DISCO DISCO Deferral Account Balances and UNCA DISCO See above 2001-94 2001-94 has been retired as a valid number. This Previously Reserved Decision 2001-94 was Merged With Decision 2001-93. It now links to 2001- 93 Dec. 22, 2001 2001-95 M GENCOs GENCO Deferral Account Balances Dec. 11, 2001 2001-102 F AE DISCO 2001-2002 General Tariff Application Part F: 2002 Distribution Tariff Base Rates Dec. 18, 2001 2001-103 TransAlta Temporary Suspension Regulation Dec. 18, 2001 2001-113 UNCA 2002 DT Interim Rates and Riders DISCO Dec. 18, 2001 2001-114 C TransAlta Year 2000 Outstanding Matters Deferral Accounts (Other than Pool Prices) Part C: TransAlta GENCO Refiling Dec. 27, 2001 2001-115 N GENCOs Amendment of Decision 2001-95 respecting EGI GENCO payment to DISCOs/TA and EGI gas unit sharing Jan. 22, 2002 2002-003 D AE Refiling GENCO and TRANSCO GENCO & Outstanding Matters (Other than Pool TRANSCO Price) Deferral Accounts Jan. 22, 2002 2002-006 E EGI Refiling GENCO Outstanding Matters GENCO (Other than Pool Price) Deferral Accounts Jan. 22, 2002 2002-007 F TransAlta Supplemental Refiling GENCO GENCO Outstanding Matters (Other than Pool Price) Deferral Accounts Jan. 22, 2002 2001-113 UNCA Errata on 2002 DT Interim Rates and Errata DISCO Riders Jan. 24, 2002 2002-008 O102 GENCOs Refiling of GENCO Pool Price Deferral Accounts resulting from Decision 2001- 95. Apr. 2, 2002 2002-023 G DISCOs AE and UNCA DISCO Outstanding Matters Refilings resulting from Decisions 2001-83, 2001-92 and 2001-93
102 This report was inadvertently issued as Part N.
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Issue Date Decision Part Applicant Decision Name Number Apr. 2, 2002 2002-024 P AE and Refiling of DISCO Pool Price Deferral UNCA Accounts resulting from Decisions DISCOs 2001-92 and 2001-93. Apr. 16, 2002 2002-025 Q GENCOs GENCO Offer Practices and Need for Year 2000 Market Review Apr. 18, 2002 2002-026 R AE and Allocation of DISCO PPDA Balances to UNCA Rate Class DISCOs To Come TBD DISCOs Securitization Decision and Determination of Carrying Cost Rates Beyond April 1, 2002 To Come TBD AE and Implementation of Rate Riders to Collect UNCA remaining DISCO PPDA and DISCOs Outstanding Matters Amounts
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APPENDIX 2 - BOARD ALLOCATION TEMPLATE
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APPENDIX 3 - AE DISCO DEFERRAL ACCOUNTS The AE DISCO Deferral Accounts were established in the Alberta Power Limited 1999/2000 Tariff Application Phase 1 Negotiated Settlement (1999/2000 Settlement) approved by the Board in Decision U99046.103
AE DISCO’s Deferral Accounts were established pursuant to Clauses 28-31 of the 1999/2000 Negotiated Settlement.
AE DISCO’s Pool Price deferral account was established pursuant to Clause 28 of that Settlement according to the following formula:
Pool Price Deferral = (Lf-LFTf) * (PPa-PPf) – (EVa-EVf) where:
Lf = Hourly forecast of Distribution load LFTf = Hourly forecast of load subject to pool price flow through (Pool Opportunity Rate) PPa = Actual hourly pool price PPf = Hourly forecast of pool price EVa = Actual hourly Entitlement Value refund EVf = Hourly forecast of Entitlement Value refund.
AE DISCO’s Voluntary Load Curtailment Program (VLCP) deferral account was established pursuant to Clause 29 of the 1999/2000 Settlement according to the following formula:
Load Curtailment (VLCP) Deferral = (LCa * (RCa– PPf)) + VLCC where:
LCa = Actual load curtailed as a result of the Voluntary Load Curtailment Program RCa = Actual per unit incremental retail revenue loss by APL as a result of the Voluntary Load Curtailment Program. PPf = Hourly forecast of Pool Price VLCC = Additional costs of operating the Power Pool’s VLCP paid to the Power Pool of Alberta.
103 The 1999/2000 Settlement was made under AE’s former name of Alberta Power Limited (APL).
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The deferral account formula approved by the Board for AE DISCO for the Direct Access Tariff (DAT) pursuant to Clause 30 of the 1999/2000 Settlement was as follows:
DAT Deferral = LDATa * (PPa-PPf) – LDATa /(Lf – LFTf ) * (EVa-EVf)
where:
LDATa = Actual hourly Direct Access Tariff load exposed to the Pool Price PPa = Actual hourly pool price PPf = Hourly forecast of pool price Lf = Hourly forecast of Distribution load LFTf = Hourly forecast of load subject to pool price flow through (Pool Opportunity Rate) EVa = Actual hourly Entitlement Value refund EVf = Hourly forecast of Entitlement Value refund.
The deferral account formula approved by the Board for AE DISCO to account for load switching from Pool Opportunity Rate (POR) to firm rates pursuant Clause 31 of the 1999/2000 Settlement was as follows:
POR to Firm Deferral = [AE] Distribution Incremental or Decremental Cost – [AE] Distribution Incremental Revenue.
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APPENDIX 4 - CALCULATION OF OPTION G SYSTEM BENEFITS AND OPTION G/DAT POOL PURCHASE COSTS
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APPENDIX 5 – VIEWS OF THE PARTIES REGARDING APPROPRIATENESS OF INCLUDING DAT AND OPTION G CLASSES IN THE ALLOCATION
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Introduction AE indicated that it excluded DAT customers from all portions of the DISCO deferral account allocation since their energy consumption was based on pool price during 2000. To the extent that DAT customers felt entitled to any Generation Deferral credits, AE was of the view that DAT customers have already been compensated in kind by proxy due to the fact that the DAT C- credit (DAT Rate Adjustment) was designed by the Board in such a way that, in months where pool price was lower than forecast, and therefore the C-credit would have been negative, the C- credit was floored at 0$/MW.h and therefore the DAT customers would not have had to pay the DISCO for any shortfall.
UNCA noted that in Decision 2000-3, the Board stated:
“the Disco Deferral account should only relate to load for customers served on “hedged” rates. The Disco deferral account should not include load related to Disco-to-Disco transfers nor should it include temporary energy loads that are priced as flow-through of pool prices.”
UNCA submitted that DAT customers received a flow through of pool price but were also hedged to the degree that they received a “Pool Price Adjustment” (PPA) credit that is derived from actual monthly entitlement refunds. Consequently, UNCA was required to make the DAT adjustment to the unadjusted Pool Price Deferral Account to capture the pool price variance associated with this particular customer class. As a result, an adjustment has been made to the deferral account consisting of the net effect of two components:
(1) Pool price deferral component related to DAT volumes: -$87.0 million (2) PPA credit component related to DAT volumes: +$73.0 million
UNCA’s DAT adjustment = (Actual pool price – Forecast pool price) * (Actual DAT volume) - (Actual PPA – Forecast PPA) * (Actual DAT volume)
The net effect of UNCA’s DAT adjustment was a reduction to the pool price deferral account of $14.0 million, as shown on Schedule 2.2104.
UNCA made a similar adjustment for customers served on Option G/21 since they also received a flow through of pool price. UNCA submitted that the difference between actual and forecast pool price for the Option G/21 volumes should be reflected in the pool price deferral account.
104 Exhibit 312.
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Option G/21 customers received a Generation Access Credit (“GAC”) based on actual pool price whereas the forecast of GAC credits was based on the forecast pool price.
As a result, the adjustment for Option G/21 load is similar to the adjustment for DAT load:
Option G / 21 adjustment = (Actual pool price – Forecast pool price) * (Actual G/21 volume) - (Actual GAC – Forecast GAC) * (Actual GAC kW)
The net effect of the Option G/21 adjustment was an increase to the pool price deferral account of $19.2 million, as shown on Schedule 2.2105.
Since DAT and Option G energy consumption did not contribute to the pool price deferral account deficiency (since the energy is charged at pool price), the rate class allocation of generation revenue was adjusted to reflect that. In Decision 2000-52 regarding the Interim Settlement of TransAlta’s 2000 Distribution Deferral Account, the Board noted that “the DAT rate provides a shield for DAT customers on the hedged portion of their load from the average pool price increase through the monthly pool price adjustment. Consequently, DAT customers have received a legislated benefit to the same extent as other rate classes. Similarly, however, DAT customers since January 1, 2000 have been exposed to the pool price on the unhedged portion of their load and have not contributed to the TransAlta DISCO deferral account deficiency.” UNCA considered the Board’s comment applies equally to Option G customers, who were similarly exposed to the pool price on the unhedged portion of their load.
UNCA indicated that the Pool Price Adjustment of DAT Rate 68XX and the Generation Access Charge/Credit of Option G were not designed with expectation of the high pool prices experienced in the later months of 2000 and the responding changes in customer load. Generation costs were therefore not fully offset by generation revenue from DAT and Option G customers. The difference in generation costs and revenue for DAT and Option G customers has therefore been allocated to other rate classes in proportion to each rate class’s share of pool purchase costs, based on the assumption that DAT and Option G load reductions would generally have occurred in proportion to pool purchase costs.
UNCA submitted that another way of making the adjustment for DAT customers would have been to exclude the DAT energy volumes in the initial unadjusted Pool Price Deferral Account, and simply add the difference between actual and forecast PPA credits.
UNCA termed the net effect of the two components the DAT adjustment that was a reduction to the Pool Price Deferral Account of $14.0 million, as shown on Schedule 2.2106. The DAT adjustment is a pool price dependant variance and appropriately reflects the structure and purpose of the basic pool price deferral formula: i.e. to capture 100% of the price variance at actual volumes.
UNCA noted that the DAT adjustment does not appear to have been challenged by any of the parties to the proceeding.
105 Exhibit 312. 106 Exhibit 312.
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UNCA’s noted that its approach to allocating the deferral account to Option G loads was intended to be just and reasonable respecting all consumers. UNCA submitted that it was consistent with the rate design principles in the year 2000. UNCA relied heavily on the rate design principles approved in Decision U99035 and accounted for actual revenue generated by the resulting tariff in place in 2000.
UNCA submitted that the elements that lead to the design of Option G prior to 2000, were not relevant to the issue of allocating the pool price deferral account for 2000.
Views of IPCCAA IPCCAA proposed changes to the UNCA methodology with respect to DAT loads. IPCCAA noted that there appeared to be agreement that DAT loads have already borne their share of Pool Price and UOV related deferrals through the DAT mechanism. Therefore there is no reason to include DAT loads in the allocation of the Pool Price and UOV related deferral amounts. This is the approach that ATCO has taken. UNCA, on the other hand, includes DAT loads in the calculation of the amount of the Pool Price Deferral account, then subtracts the Pool Purchase component through the DAT adjustment. DAT loads are then included in the allocation of the Pool Price and UOV components. Recognizing that no net amounts are to be allocated to DAT UNCA requires an adjustment to revenue to arbitrarily re allocate any net amounts to other rate classes. The DAT adjustment also recognizes the UOV component passed through to the loads in the DAT tariff.
IPCCAA submitted that it would be simpler to:
• Exclude DAT load from the calculation of the Pool Price component of the deferral account. This recognizes that the DAT loads were exposed directly to the actual Pool Price for their actual load. This step would reduce the Pool price deferral to be allocated by $87 million from $2,589 million to $2,502 million (Ex 913).
• Recognize that the pool price adjustment (PPA) credits in a DAT tariff were a share of the monthly UOV refunds received by the DISCO that were paid directly to the DAT loads. Therefore the monthly PPA credits should simply be subtracted from the amount of the entitlement deferral prior to allocation among rate classes. This would reduce the UOV deferral refund to be allocated by $73 million from $(2,160) million to $(2,087).
If these adjustments are made then the DAT load can be excluded from the allocation of the Pool Price and entitlement related deferral amounts.
This approach would be far more transparent than that proposed by UNCA in the bottom up allocation approach.
If the top down approach were to be adopted for UNCA such adjustments would also be required.
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Treatment of Option G in UNCA’s Bottom up Allocation UNCA has presented pages of allocations upon which to base the allocation of deferral amounts by rate class. But one thing stands out – none of these calculations determine an appropriate level of allocation to Option G loads. The amount to be allocated to Option G is simply selected to be equivalent, on a unit basis, to the amounts allocated to Rates 63XX and 65XX.
If examined further it is found that the UNCA calculation method would allocate a much larger amount to Option G, requiring a manual intervention in the calculation to limit the amount allocated to the equivalent amount described above. Absent the intervention the deferral would be larger on a unit basis than the average deferral over the entire year (Ex 913 p. 10 of 10). And Option G load was not even around for the last 4 months, when the average Pool Price (at $210/MWh) was more than twice the level for the first 8 months. In fact, both the bottom up and top down approaches calculate that less than 45% of the deferral balance was accumulated in the first 8 months (Ex 913 UNCA Sch 8 w IPCCAA Recommended Changes, Tab: Deferral). UNCA’s assertion that the Option G tariff was intended to be revenue neutral to 6300/6500 and therefore these loads should pay the same rider as 6300/6500 simply does not overcome the shortcoming that they cannot calculate an appropriate deferral for Option G. Clearly UNCA’s determination of the deferral account allocation in respect of Option G load is baseless and ought to be rejected.
For all other rate classes (except, perhaps irrigation) the top down (requiring no revenue calculation) and bottom up allocation (including a revenue calculation) are very similar.
UNCA has not attempted to reconcile their bottom up calculation (with or without Option G adjustments) with the top down allocation to Option G. Through Ex 913 and this argument IPCCAA has established that the two methods can be adequately reconciled with appropriate adjustments to the revenue calculations.
If the Board sees merit in the bottom up approach versus the top down approach there are appropriate adjustments that can be made to UNCA’s Option G revenue calculation to provide a meaningful result.
UNCA, in Table 2.3 calculates the amount by which the GAC payments to Option G load exceed the pool price component of the deferral account. The reasons the GAC credits exceeds the Pool Price component of the deferral account (calculated as [actual Pool Price less forecast Pool Price] X Actual load) are largely the result of load curtailments. At times of the highest Pool Price (and therefore likely the higher the difference between actual and forecast Pool Price) the Option G load was likely reduced through curtailment and therefore lower the amount by which the Option G component of the Pool Price deferral account offset the GAC credits.
The GAC credits were the mechanism that (for a load that did not respond to Pool Price and had the same load characteristics as the rate class) made up the difference between Pool Price and fixed price rates – it was the hedge mechanism. The higher the Pool Price was the higher the GAC payments would be. The more the curtailments the lower the Power Pool bill for Pool priced energy (and the lower the calculated Pool Price deferral) but the GAC refund was not affected by the curtailment. The more curtailment there was the lower the revenue would be.
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The amount by which GAC credits exceeded the calculated Pool Price deferral is the refund of the hedge value in respect of curtailed load.
On the revenue side of the bottom up approach UNCA has subtracted all of the GAC credits paid to Option G load from the revenue received from Option G. What this means is that the Option G customers were required to pay themselves for the hedge value in respect of curtailed load. Even with UNCA’s revenue adjustment the Option G loads are required to pay half (actually 10/22: $10 million deferral allocation divided by $10 million deferral allocation plus $12 million revenue adjustment) of the hedge value to themselves in respect of curtailed load.
As discussed with Mr. Wallace, it is possible that the amount of curtailment would have resulted in UNCA recognizing no revenue (or even negative revenue) from Option G loads. As it is, the revenue recognized was only $10.6 million. At $26/MWh (roughly the average unit revenue for industrial load in Schedule 8-C, prior to the introduction of STS on June 1) the fixed rate revenue would be approximately $30 million ($26/MWh x 1159.5 GWh) or approximately $19.4 million higher than the $10.6 million recognized by UNCA. The difference is the GAC payments in respect of curtailed load, shown on Schedule 2.4 as $19.3 million.
Another issue is how UNCA calculated revenue for Option G in January and February. The “old” rates were in place but to be consistent with the deferral accounts UNCA, for revenue purposes, assumed the “new” rates were in effect January 1.
Dividing the Option G revenue by month (Ex 377) by the energy per month, the unit revenues are as follows:
Jan Feb March April May Option G Revenue ($/MWh) 13.04 13.10 17.81 9.83 22.26 Average Pool Price ($/MWh) 46.46 47.07 77.19 93.68 51.66
The unit revenues were derived by dividing the monthly revenue (Ex 377) by the monthly energy (Schedule 8-G Rev 1). The revenues have subtracted all GAC payments made and therefore reflect the Option G loads “paying themselves” the hedges in respect of curtailed loads.
Comparing the unit revenues for January, February and May, months with similar low Pool Prices and therefore fewer curtailments and associated revenue distortions arising from the treatment of GAC credits, we see the January and February unit revenues significantly lower than May. This is likely the result of an error in calculating revenue in January and February unit revenue months during which the GAC mechanism was tied to the old Rate 790.
The revenues shown appear to reflect the Pool Purchases less forecast H-factor (same in all rates) less all GAC credits paid out. The response to IPCCAA-UNCA-2 provided the GAC calculators for January through August. For January and February the GAC would equal zero at a Pool Price of $25.07/MWh. In March through May, the GAC would be zero at $33.18/MWh.
From IPCCAA-UNCA-2, one can derive the average energy cost for Rate 790 (> 2 MW) (used to determine the GAC for January and February) as $25.07/MWh. For March onward, the
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average energy cost for Rates 6300/6500 was $26.48/MWh, a difference of $1.41/MWh. Therefore, even if UNCA were to base it’s revenue calculation in January and February on the old rate structure (something not done for any other rate class), absent significant curtailment, one would expect the average revenue in January to be less than the March onward revenue by less than $1/MWh.
But the unit revenue in January and February is significantly lower. This is likely the result of UNCA incorporating the “H-factor” of $6.70/MWh in the January and February revenue calculations for Option G. This is in error because the H-factor was effectively built in the January and February GAC calculation. This is consistent with the Pool Price at which the GAC equals zero differing by $8.11/MWh ($33.18-$25.07). The difference equals the H-factor plus the difference in average const in the rates ($8.11 = $6.70 + $1.41).
To demonstrate the impact of an inappropriate H-factor treatment, we offer the following example: At a Pool Price of $33.18, the March unit revenue would be calculated as ($33.18 –H- factor – GAC) or $26.48/MWh ($33.18-$6.70-$0.00). For January, UNCA would calculate revenue as $18.22/MWh [$33.18 - $6.70 - $8.26/MWh GAC where GAC = $4.98/kW (IPCCAA-UNCA-2 January GAC for Pool Price of $33.18/MWh) divided by 1 kW x 744 hours x 81% load factor). Clearly, for the same load the revenue calculated should be similar in January and March. For this example we have assumed a load shape that has a Pool Purchase cost equal to the average Pool Price and a load factor equal to the rate class average.
To correct this oversight, UNCA should increase the January and February Option G revenue by $6.70/MWh or $1.9 million over the two months ($6.70/MWh x 286.8 GWh from Schedule 8- G).
In its Argument UNCA did not address any of the issues (identified by IPCCAA in evidence and cross-examination) that are relevant to determination of the deferral account allocation to Option G loads. UNCA’s entire Option G argument consisted of a single statement:
It is UNCA’s submission that the fundamental logic of the Option G adjustment still holds (UNCA Argument, Page 41)
As outlined in IPCCAA’s argument (pages 43-46, under 5.1.4 Allocation Methodology “top- down vs. bottom-up”) the issue with respect to treatment of Option G in the UNCA deferral account allocation is not the “Option G adjustment”. The main issue is the quantum of the deferral account assigned or allocated to the Option G rate class.
UNCA did not calculate a deferral account allocation for Option G. UNCA’s basic allocation methodology would calculate an Option G deferral account allocation of nearly $20/MWh almost twice the $9/MWh average deferral level for Rates 6300 and 6500 over the first eight months of 2000 (with UNCA’s revenue adjustment the allocation to Option G is $10.4 million; if the revenue adjustment were not made the calculation would be a shortfall of $22.9 million or $19.75/MWh). UNCA merely pronounced that $9/MWh seemed a fair amount to assign to Option G. Assignment of this unit deferral amount appears to be the “Option G adjustment” the logic of which UNCA concludes still holds.
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UNCA explained the logic for the assignment thus:
Upon further examination, UNCA considers that the GAC mechanism provided Option G customers with a hedge equivalent to fixed-price customers, and consequently Option G customers should be allocated an appropriate share of the Disco deferral account.
This share was calculated by determining the average deferral amount of $8.96/MWh for Rate Classes 63XX-65XX during the first eight months of 2000, when Option G was available. An adjustment to Option G revenue was then added in Column C of Schedule 8-C Rev 1, such that the same average deferral amount resulted for Option G customers. This adjustment ensures the allocation to Option G customers of costs arising from the Disco’s unhedged pool purchases is at a level equivalent to the allocation to the fixed- price rate customers on which the GAC credit was based. (FIRM.UNCA DISCO-13)
The only “fundamental logic” inherent in the Option G treatment by UNCA is that the unit amount assigned to Option G was arithmetically equivalent to the amount allocated to Rate 6300 and 6500.
UNCA only had to assign a deferral allocation to Option G because they had made errors in the revenue calculation for Option G. With appropriate treatment of Option G revenue, the UNCA calculation methodology is sound, requiring no assignment of unit deferral amounts and no revenue adjustments. The appropriate revenue adjustments (adding back the GAC payments in respect of curtailed load and not double counting the H-factor in January and February) are described in detail in IPCCAA’s Argument at pages 44-46.
The FIRM Group, in numerous parts of their Argument, rely on inappropriate comparisons to suggest that an hourly allocation of Pool Purchase and UOV components of the deferral account results in lower allocations to Option G loads. IPCCAA has responded to these statements under its general reply to the FIRM Group allocation argument.
Views of FIRM The FIRM Customers recommend that any DAT adjustment to the deferral amount be computed with hourly data whenever hourly data is available to ensure precise and accurate adjustments.
The FIRM Customers recommend that any Option G/21 adjustment to the deferral amount that is directly linked to the hourly pool price be calculated with hourly data whenever hourly data is available. Similarly, the cost responsibility should be calculated on an hourly basis to ensure that costs are not shifted.
Views of ANC/MW UNCA is applying for an order that the Option G Rate Class (“Option G”) pay a portion of certain costs incurred from January 1 to August 31, 2000.
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Alberta Newsprint Company and Millar Western Forest Products Limited (“ANC/MW”) made up approximately 54% of Option G during this period.107 Together, UNCA’s proposed Option G rider would increase ANC/MW’s Option G energy costs by 131%.108 The Option G rider would increase Option G’s energy costs as a whole by 118%.109
ANC/MW strongly oppose UNCA’s application. ANC/MW believe that:
• The costs UNCA are trying to recover from Option G are not properly part of the deferral account; • The Board does not have the jurisdiction to retroactively increase Option G rates; and • The premise of UNCA’s application is flawed. UNCA’s application does not reflect the fundamental nature of Option G and to allocate a portion of the deferral account to Option G would be unjust and unreasonable
Each of these arguments is discussed below.
The costs UNCA are trying to recover from Option G are not properly part of the deferral account The deferral account was established by Decisions U99099 and 2000-3. The deferral account formula in Decision 2000-3 is:
Pool price deferral = (Actual pool price – Forecast pool price) x (Actual energy purchases) – (Actual DISCO entitlement – Forecast DISCO entitlement).110
Notwithstanding this, UNCA used a different formula to calculate the amount it now seeks to recover. In addition to the pool price variance reflected in the 2000-3 formula, UNCA adjusted the formula as follows:
Option G / 21 Adjustment = (Actual pool price – Forecast pool price) x (Actual Option G / 21 energy purchases) – (Actual GAC credits – Forecast GAC credits).111
The effect of UNCA’s proposed change to the Board-approved formula would be to increase the deferral account by $19.24 million.112
UNCA admitted that the pool price deferral account does not have the Option G adjustment in it. However, UNCA felt that the intent of the deferral account was to “more or less, keep the utility
107 Transcript Volume 25, Direct Evidence of ANC/MW Panel, page 5847, line 16 to page 5848, line 5. 108 Exhibit 1503, Millar Western/Alberta Newsprint Response to Undertakings. This impact is in addition to the impact of UNCA’s proposed firm rate rider on ANC/MW’s firm electricity costs for their non-responsive load. 109 Exhibit 1503, Millar Western/Alberta Newsprint Response to Undertakings 110 Decision 2000-3, page 12 111 Exhibit 341, UNCA Application, section 2.3, page 7 to page 8 and Exhibit 337, Schedule 2.3 G,21 (Note: this version of the “Option G/21 Adjustment” was taken from Exhibit 337). 112 Exhibit 337.
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whole” and therefore it was appropriate to include the Option G adjustment in the calculation of the deferral account.113
With respect, ANC/MW do not believe that Decisions U99099 and 2000-3 suggest that the intent of the deferral account was “to keep the utility whole” or that the Option G adjustment to the deferral account formula is appropriate. To the contrary, following Decision U99099, TransAlta complained that “the intent of what should be covered by the deferral accounts as stated in the text of the Decision [U99099] was not reflected in the formulas provided in the Decision.”114 On this basis, TransAlta asked the Board to revise the formula established in Decision U99099. The correct formula, as submitted by TransAlta, was precisely the formula that was approved in Decision 2000-3.115 As indicated, there was no adjustment for Option G in this formula.
The intent of UNCA’s proposed modification of the Board-approved formula is to attempt to pass the cost of greater than forecast GAC’s116 onto its customers. As indicated by UNCA:
“Now, what actually happened with Option G load is that we received a lot less revenue because the credits paid out were much bigger than forecast hedges, essentially, that were built into the other fixed rates.
So, the revenue actually received from those customers was far less than forecast cost.”117
UNCA’s characterization of Option G as a “fixed rate” is not correct. However, UNCA is correct that most, if not all, of the difference between the net revenues and generation costs that UNCA attributes to Option G occurs because Option G revenues were lower than forecast as a result of the GAC.118
ANC/MW believe it is inappropriate for UNCA to now try to pass these costs onto its customers. TransAlta was aware long before the deferral account was established that differences between forecast and actual GAC’s could occur and, if this happened, that this could result in both positive and negative variations in the net revenue from Option G. For example, in 1998, as a result of the forecast GAC being significantly different than it should have been, Option G customers paid approximately $15 million more than forecast.119 Notwithstanding that TransAlta was aware that these differences could occur, it did not apply to have the deferral account include amounts related to the GAC.
ANC/MW also submit that there should be no difference in treatment between the greater than forecast GAC’s that UNCA is now attempting to pass on to its customers and the $15 million
113 Transcript Volume 21, Cross-examination of UNCA, page 4598, line 3 to line 12. 114 Decision 2000-3, page 7 115 Decision 2000-3, page 7 and page 12. 116 Generation Access Charge or Credit depending on the circumstances 117 Transcript Volume 21, Cross-examination of UNCA, page 4585, line 17 to line 24. 118 Exhibit 314, Schedule 8, Rev 1. This makes sense since Option G paid for all energy purchases at power pool prices. The balance is apparently due to the imprecision in various formulae, etc. 119 Exhibit 1501, Letter dated June 24, 2000 from Alberta Newsprint Company and Millar Western Forest Products Limited to Mr. Litt.
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that Option G overpaid in 1998. In1998, TransAlta retained this overpayment. Applying the same principles, ANC/MW submit that the utility should bear the burden of this for 2000.
Based on the above, ANC/MW submit that it is both incorrect and too late for UNCA to ask the Board to change the deferral account formula to take into account changes in GAC’s. ANC/MW respectfully submit that the Board should not allow UNCA’s proposed Option G adjustment to the deferral account formula.
The Board does not have the jurisdiction to retroactively increase Option G’s rates UNCA’s application effectively requests that the Board go back to the beginning of the year 2000 and set rates as if it knew then what it knows now.120 With respect, the Board does not have the jurisdiction to do this for Option G.
The Board’s rate-setting power is set out in section 57 of the Electric Utilities Act.121
57(1) Unless section 20 of the Alberta Energy and Utilities Board Act applies, no order of the Board approving a tariff shall be reviewed, rescinded or varied during the period in which the tariff is intended to have effect, except in accordance with this section. (2) Any person affected by an order approving a tariff may ask the Board to review the order (a) if the terms or conditions provided by the tariff for discontinuing the rates have been met and the order provides for a review under this section in those circumstances, (b) if the owner of the electric utility or the Transmission Administrator has breached in a material manner a term or condition of the tariff, (c) if, since the date of the order, circumstances have changed in a substantial and unforeseen manner that renders the continuation of the tariff unjust and unreasonable, or (d) if, in the Board’s opinion, the order contains an error of fact or law, provided that the request for a review on that ground is filed with the Board not later than 90 days after the making of the order.
Decision U99099 did not mention that it applied to Option G.122 UNCA may attempt to argue that there was no explicit statement in Decision U99099 that the deferral account was to apply to any specific rate class. However, it is clear that TransAlta never intended the deferral account would apply to Option G:
1. As discussed, notwithstanding that TransAlta was aware that the GAC could vary from forecast, TransAlta did not apply to have variations in the GAC included in the deferral account;
120 Transcript Volume 21, Cross-examination of UNCA, page 4472, line 17 to line 23. 121 R.S.A. 1995, c.E-5.5 122 Decision U99099; Transcript Volume 21, Cross-examination of UNCA, page 4623, line 2 to line 10.
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2. When TransAlta sought to collect interim payments on the deferral account it did not apply to recover any of the deferral account from Option G;123 and 3. TransAlta assured ANC/MW that it did not intend to attempt to collect the deferral account from Option G.124
UNCA is now attempting to change TransAlta’s position. With respect, the Board only has the power to change Option G in very limited circumstances. Option G was intended to have effect until it expired on August 31, 2000.125
Therefore, the Board only has the jurisdiction to change Option G if UNCA can establish that either section 20 of the AEUB Act or one or more of the conditions in section 57(2) of the EUA are satisfied.
ANC/MW submit that UNCA has not done so. However, even if one of these provisions is satisfied, unless an appeal or a request for review and variance was filed from the original decision establishing Option G, the Board only has the power to change Option G prospectively.
No such application was made. Based on the above, ANC/MW respectfully submit that the Board does not have the jurisdiction to grant UNCA’s application with respect to Option G.
Option G should not be allocated part of the deferral account As indicated, ANC/MW believe that the amount that UNCA is asking Option G to pay is not properly part of the deferral account. ANC/MW also believe that the Board does not have the jurisdiction to grant UNCA’s request.
If the Board does not accept these submissions, ANC/MW still respectfully submit that Option G should not be allocated part of the deferral account. ANC/MW believe that to allocate a portion of the deferral account to Option G ignores the fundamental nature of Option G and would be unjust and unreasonable. This argument is discussed in more detail below.
Option G’s genesis was in the early 1990’s as Planned Interruption Option 12. TransAlta developed Option 12 as an interruptible source of supply to reduce its need to build new generation. In return for being interrupted, customers on Option 12 were paid a set level of credits. 126
In the mid-1990’s, TransAlta began interrupting Option 12 for economic reasons rather than system emergencies. This was inconsistent with the original intent of Option 12. In consequence,
123 Transcript Volume 21, Cross-examination of UNCA, page 4623, line 11 to page 4624, line 16. 124 Exhibit 1501, Letter dated June 24, 2000 from Alberta Newsprint Company and Millar Western Forest Products Limited to Mr. Litt (clarified in Transcript Volume 25, Direct Evidence of ANC/MW, page 5845, line 20 to page 5846, line 20). 125 Exhibit 1503, Millar Western/Alberta Newsprint Response to Undertakings, Appendix “A” 126 For history see generally - Exhibit 1501, Letter dated June 24, 2000 from Alberta Newsprint Company and Millar Western Forest Products Limited to Mr. Litt; Exhibit 1503, Millar Western/Alberta Newsprint Response to Undertakings, Appendix “A”; Transcript Volume 25, Evidence of ANC/MW; and Board Decisions U96053 and U99035.
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TransAlta and Option 12 customers entered into negotiations to attempt to arrive at an agreement that would continue to provide the benefits of Option 12 but do so in a way that was consistent with the emerging market-based nature of the electricity industry in Alberta.
These negotiations produced three alternatives. Option 12 customers could move to a firm rate; stay on Option 12; or move to a new Planned Interruption Transition Alternative Option 21. ption 21 was structured to provide a price signal that allowed the customer, rather than TransAlta, to decide whether to interrupt or not. In return, they received a reduced level of credit from Option 12 that continued to decline over time. Customers who chose Option 21 were also specifically prohibited from moving back to an “embedded energy rate” when Option 21 expired on August 31, 2000.
As TransAlta described in its Phase II 1996 General Rate Application, Option 21 was developed through consultations with IPCAA and Option 12 customers and was the equivalent of a “New World” Option 12.127 That is, rather than establish a fixed cost of electricity, Option 21 established a framework where customers were given an incentive to make decisions with respect to their electricity consumption based on the price of electricity and their own market conditions.
This agreement allowed TransAlta to retain the benefits of Option 12 under the new market- based nature of the industry. In turn, it allowed Option 21 customers the opportunity to reduce their average electricity bills by adjusting their consumption of electricity, if appropriate, in response to price signals and other market conditions. The Board approved this agreement as a negotiated settlement on August 15, 1996.
The price signal under Option 21 was based on the then Alberta power pool price plus an additional amount known as the Generation Access Charge. This situation was reasonably stable during 1996 and 1997. However, in 1998, as a result of errors in the GAC forecast, Option 21 began to pay significantly more than contemplated. To attempt to deal with this, TransAlta and the Option 21 customers agreed to reduce the GAC to zero for the second half of 1998. Notwithstanding this, as a result of the inaccurate GAC forecast, Option G paid approximately $15 million more than the forecast revenue from that class in 1998. TransAlta kept these overpayments.
At the end of 1998, further negotiations took place to allow the GAC to become a credit in the appropriate circumstances. These negotiations also resulted in an agreement that the GAC would be determined on a month-to-month basis rather than being set in advance. The Board again approved this agreement.128
The issue that was not resolved between the parties was the issue of the alternatives available to Option 21 when Option 21 expired. Notwithstanding that the original terms of Option 21 had provided that Option 21 customers could not return to an “embedded energy rate”, Option 21 felt that the alternatives that had been developed and were available to them on the expiry of Option
127 Decision U99035, page 149. 128 Decision U99035, page148 to 153.
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21 were flawed and that this position should be reconsidered. TransAlta took the position that this was an essential term of the original negotiated agreement and should not be changed.
Ultimately, the Board agreed with TransAlta and ordered that Option 21 could not return to a rate that offered fixed energy pricing.
The name of Option 21 was changed to Option G in March 2000.
Based on the above, ANC/MW believe there are at least four fundamental aspects of Option G:
1) the goal of Option G was to create an economic incentive to encourage price responsive load to respond to price signals and other market conditions; 2) by giving the incentive to Option G to respond to market conditions this provided benefits to TransAlta and its customers; 3) Option G customers responded to these incentives on a real-time basis; and 4) Option G was a negotiated business arrangement. As such, changes were only made to this arrangement on a “going forward” basis.
Each of these characteristics is discussed in more detail below.
The goal of Option G was to incent price responsive load to adjust their electricity consumption in response to market signals including the price of electricity.129 This established a dynamic environment that was fundamentally different from UNCA’s other rates.
At the heart of UNCA’s position that Option G should be allocated a portion of the deferral account is the so-called “principle” of revenue neutrality. However, given the dynamic nature of Option G, it was never intended that revenue neutrality would actually be achieved.130 As discussed below, the quid pro quo for adjusting their consumption and freeing up supply was that Option G customers would have the opportunity to reduce their average electricity rates.
Contrary to UNCA’s position, this is fundamentally inconsistent with maintaining revenue neutrality.
The underlying purpose of Option G was that by giving Option G an incentive to adjust their consumption and freeing up supply this provided a benefit to TransAlta and its customers. These benefits were accepted as being in the public interest.131 ANC/MW believe that a hindsight analysis of these benefits is inappropriate. However, it is clear that these benefits were provided. UNCA agreed that Option G responded to pool price signals.132 This is graphically depicted in
129 Transcript Volume 26, Cross-examination of FIRM, page 6112, line 21 to page 6114, line 8. 130 Transcript Volume 25, Cross-examination of ANC/MW, page 5850, line 11 to page 5855, line 24. 131 Decision U96053. 132 Exhibit 306, IPCCAA.UNCA DISCO 3-1(j). Other parties also accepted this. For example see Transcript Volume 26, Cross-examination of FIRM, page 6095, line 17 to page 6096, line 4 and page 6114, line 13 to page 6116, line 1.
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Exhibit 1503. 133 UNCA also agreed that this reaction caused a reduction in pool prices and benefited TransAlta and its customers.134 No other customer class that UNCA is now applying to recover the deferral account from provided these benefits.
UNCA argued that they took into account these benefits in arriving at their proposed allocation. This is not the case. There is no estimate anywhere in UNCA’s materials of the size of these benefits.135
As mentioned, in return for providing these benefits, Option G had the opportunity to reduce their average cost of electricity. However, the amounts that were paid to TransAlta did not reflect the only costs that Option G incurred in respect of their electricity consumption.
ANC/MW made decisions during the first eight months of 2000 based on the framework that was then in place under Option 21/G. They spent money and expended time and effort to ensure that they were in a position to respond to power pool price signals, they had staff watch prices around the clock, they shut down their facilities at appropriate times, they shifted load based on price, they gave up production and turned down orders, in some cases affecting market share and long-term customer relationships – all based on real-time economic signals.136
ANC/MW are not complaining about this. This is the way Option G was supposed to work.137
However, ANC/MW submit that it would be fundamentally unjust and unreasonable to effectively change the economics that were in place over the first eight months of 2000 when they have no opportunity to revisit the decisions that were made at that time and likely would have made different decisions had different economics been in place.
Given the above, Option G ultimately became a business arrangement between the Option G load and TransAlta. The history of this relationship was that the parties lived with the conditions they had established. These set parameters within which each of the parties knew that conditions could vary. As conditions changed over time, if these got too far out of balance the parties would engage in further discussions and negotiations to attempt to agree on changes that would continue to maintain the mutual benefits under Option G. If, as a result of these discussions it was agreed changes were required, these would be done on a “go forward” basis.138 Through this framework, TransAlta was able to maintain the benefits they were getting under Option 12. It would appear TransAlta was happy with these benefits.139
133 Exhibit 1503, Millar Western/Alberta Newsprint Response to Undertakings, Schedule 1 134 Transcript Volume 21, Cross-examination of UNCA, page 4600, line 2 to line 21 and page 4629, line 1 to line 13 (Note: at line 12 the Transcript reads “produce”. Ms. Kirrmaier in fact said, “reduce”.) and Exhibit 316, FIRM.UNCA DISCO 13(b). 135 Transcript Volume 21, Cross-examination of UNCA, page 4629, line 14 to line 17. 136 Transcript Volume 25, ANC/MW Panel Questioned by the Board, page 5860, line 19 to page 5865, line 24. 137 Transcript Volume 25, ANC/MW Panel Questioned by the Board, page 5864, line 15 to page 5865, line 12. 138 Transcript Volume 25, ANC/MW Panel Questioned by the Board, page 5874, line 9 to page 5875, line 20. 139 Transcript Volume 21, Cross-examination of UNCA, page 4629, line 25 to page 4630, line 12.
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UNCA is attempting to fundamentally change the way that Option G was developed and changed, if necessary, over time by applying to have Option G changed on a retroactive basis. ANC/MW understand that, subject to the EUB Act and the EUA, the Board has the power to reopen negotiated agreements. Notwithstanding this, ANC/MW believe the Board should be concerned with the “sanctity” of negotiated contracts and believe that this principle has even greater application to Option G and emerging market conditions than the normal negotiated arrangements the Board is familiar with.140
Option G represented a negotiated commercial arrangement. ANC/MW respectfully submit that if a true deregulated market for electricity is going to develop in Alberta, the Board must avoid any perception that it has the potential to distort the marketplace after-the-fact.141 ANC/MW believe this is particularly important on the supply side of the market where customers should be encouraged to enter into creative arrangements to supply load-curtailment or alternatively, reliability to the system with the knowledge that these arrangements are not going to be reopened after-the-fact.
In summary, ANC/MW believe that the above aspects of Option G should be a fundamental consideration in the Board’s determination of whether Option G should be responsible for any of the deferral account. TransAlta was aware of the history of Option G, the relationship between the parties, and the benefits that Option G brought to the system. TransAlta did not apply to have Option G pay a portion of the deferral account. With respect, UNCA was not aware of the history of Option G and ignored these considerations.142 UNCA simply treated Option G the same as all other rates and applied a traditional utility rate design/cost allocation approach.143 As is apparent, there is nothing traditional about Option G.
ANC/MW submit that on a proper characterization of Option G that takes into account the unique nature and circumstances of Option G it would be unjust and unreasonable to require Option G to pay the applied for amount.
Summary ANC/MW summarized their argument as follows:
1) The costs UNCA is trying to recover from Option G are not properly part of the deferral account; 2) The Board does not have the jurisdiction to retroactively increase Option G rates; and 3) The premise of UNCA’s application is flawed. UNCA’s application does not reflect the fundamental nature of Option G and to allocate a portion of the deferral account to Option G would be unjust and unreasonable.
140 Transcript Volume 25, ANC/MW Panel Questioned by the Board, page 5859, line 4 to line 9 and page 5869, line 6 to line 21. 141 Transcript Volume 25, ANC/MW Panel Questioned by the Board, page 5874, line 9 to page 5875, line 20. 142 Transcript Volume 21, Cross-examination of UNCA, page 4615, line 22 to page 4622, line 5. 143 Transcript Volume 22, UNCA Questioned by the Board, page 4759, line 13 to page 4760, line 12 and page 4762, line 11 to page 4763, line 2.
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On this basis ANC/MW submitted that the Board should reject UNCA’s application with respect to Option G.
ANC/MW is very concerned with UNCA’s Argument and its treatment of the Option G issue. There are a number of significant issues in this proceeding. However, none of these have the potential to result in as large an increase to individual customer bills as UNCA’s proposed treatment of Option G does to Option G. UNCA is aware of this. UNCA is also aware that its proposal with respect to Option G is strongly opposed by ANC/MW. Notwithstanding this, UNCA’s Argument with respect to Option G is less than a page long. The majority of this simply quotes UNCA’s response to FIRM.UNCA DISCO-13(c-d).144 Notwithstanding the significance of this issue there is nothing in UNCA’s Argument that attempts to address the fundamental issues that were raised during the course of the hearing with respect to Option G.
ANC/MW is also concerned with FIRM’s Argument on the Option G issue. FIRM devoted considerable space in their Direct Evidence to discussing why they believed Option G should be allocated a portion of the deferral account. Notwithstanding this, there is nothing in its Argument that addresses Option G.
ANC/MW are very concerned that UNCA and FIRM did not make their full argument with respect to Option G and that their Reply Arguments will deal with Option G in much greater detail. If, on reviewing these, it appears that UNCA and FIRM make submissions on Option G in their Replies that should have been raised in argument, ANC/MW expressly reserve the right to respond to these submissions.
The remainder of ANC/MW’s Reply responds to the minor points in UNCA’s Argument with respect to Option G and some other general comments in UNCA and FIRM’s Arguments.
UNCA summarizes its position with respect to Option G as follows:
“This is an appropriate revision and Option G/21 should be subject to the 2000 Pool Price Deferral on the same basis as other customers on a ‘fixed price’ rate.”145
ANC/MW will not repeat its Argument. ANC/MW respectfully submit that the evidence is overwhelming that Option G is not a ‘fixed price’ rate. However, even more significantly, ANC/MW submit that this displays the fundamental lack of consideration UNCA gave to the Option G issue.
It is clear that Option G is different from UNCA’s other rates. It is clear that Option G provided significant benefits to TransAlta and its customers. It is clear that Option G customers incurred significant costs beyond their direct electricity costs in preparing to respond to pool price signals and in responding to those signals. Finally, it is clear that TransAlta and Option G had a protocol with respect to how changes in Option 21/G would take place, if necessary.
144 UNCA Argument, pages 39 to 40. 145 UNCA Argument, page 41, quoting from Exhibit 1001, FIRM Direct Evidence.
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Notwithstanding these fundamental aspects of Option G, UNCA could not be bothered to consider these in forming its position. UNCA put itself forward as, for the most part, disinterested in the precise allocation of the deferral account and held itself out as simply offering the Board suggestions on how this allocation might be done. With respect, ANC/MW believe that if UNCA were truly acting independently, once it was informed of the history and nature of Option G it would have performed a detailed analysis that addressed these considerations. As mentioned, UNCA did not do this. Given this, ANC/MW respectfully suggest that UNCA’s position with respect to Option G can in no way be considered to be based on a full and complete analysis and effectively no weight should be placed on their views on this point.
At a more general level, UNCA makes a strong plea that the costs that are the subject of this proceeding were “undertaken for the benefit of the Customers, not UNCA” and that disallowance of any of these amounts would, among other things, “be a serious breach of the regulatory compact.”146
Again, ANC/MW will not repeat its Argument. This issue is not nearly as simple as UNCA suggests. To the extent that TransAlta incurred costs related to Option G that were greater than forecast, TransAlta and its customers also received benefits from Option G. The Board approved these benefits as being in the public interest.147 Presumably, with higher pool prices and greater response these benefits were also greater than forecast.
UNCA does not attempt to account for these benefits. Further, it is interesting that UNCA now argues that any “extra” amounts that it incurred with respect to Option G for the year 2000 were only undertaken for the benefit of customers. This argument stands in direct contrast to the position taken by TransAlta in 1998 when it retained the overpayment in GAC’s from Option G for the benefit of its shareholders.
UNCA also argues that it was “required to make” the Option G adjustment to the pool price deferral account.148 With respect, UNCA was not required to make this adjustment. It chose to apply to vary the Board-approved deferral account because it takes the position that the deferral account is in place to “keep it whole”. The only real reason for UNCA’s proposed Option 21/G adjustment is to capture differences between actual and forecast GAC’s and to attempt to pass these differences onto its customers.
Finally, UNCA submits that its approach is to essentially allocate the energy supply costs incurred in 2000 “as if those costs had been known at the time the rates had been put into effect.”149 ANC/MW respectfully submit that this again highlights the flaws in UNCA’s approach.
As indicated in ANC/MW’s Argument, UNCA is focused solely on reallocating UNCA’s costs. This approach completely ignores the costs that were incurred by Option G beyond Option G’s direct electricity costs.
146 UNCA Argument, pages 1 and 2. 147 Decisions U96053 and U99035 148 UNCA Argument, page 3. 149 UNCA Argument, page 39.
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This approach also ignores the costs that were not incurred by TransAlta because Option G customers responded to pool price signals, thereby reducing pool prices and the ultimate amount in the deferral account (i.e., it ignores the Option G benefits that TransAlta contracted for).150
Finally, UNCA’s approach ignores the evidence. The uncontradicted evidence was that if the Board were to redesign rates for 2000 based on what it knows now that “[w]e would have had larger time-of-use differentials and other incentives for customers to curtail at high-priced periods.”151 This is the complete opposite of UNCA’s proposal. UNCA would have the Board reduce the incentive that was in place in 2000 for price-responsive loads by clawing back a portion of the benefits that Option G achieved by responding to pool price signals.
As an aside, this is similar to the result that would be achieved by applying FIRM’s methodology. FIRM suggests that its allocation methodology is more consistent with the price signals given to price responsive loads. However, by allocating UOV’s on an hourly basis the opposite effect is in fact achieved. Customers who did not respond to price signals are actually rewarded for this by receiving a greater share of the UOV’s while customers who did respond are penalized.
ANC/MW submit that these inconsistencies highlight the inherent flaws in UNCA and FIRM’s proposals. They also highlight the inappropriateness of allocating a portion of the deferral account to Option G.
ANC/MW respectfully submit that there is nothing in UNCA or FIRM’s Arguments that raise any further significant issue with respect to the appropriate treatment of Option G. These issues were fully discussed in ANC/MW’s Argument.
ANC/MW still submitted that the Board should reject UNCA’s application with respect to Option G.
Views of UNCA The fundamental logic of Option G adjustment is similar to the DAT adjustment in that Customers served on Option G receive a flow through of pool price but are also hedged to the degree that they receive a GAC credit or charge that is calculated from actual pool price. Consequently, UNCA was required to make the Option G adjustment to the unadjusted Pool Price Deferral Account to capture the pool price variance associated with this particular customer class.
Option G adjustment = (Actual pool price – Forecast pool price) * (Actual Option G volume) - (Actual GAC – Forecast GAC credit) * (Actual Option G kW)
150 See ANC/MW Argument at pages 7 through 14. See also IPPCA Argument at page 25. This table indicates that Option G customers average pool price purchase costs were only approximately 2/3 of the costs incurred by other customers. This, in addition to the other evidence referred to in ANC/MW’s Argument shows the dramatic response of Option G customers to pool prices and downward pressure on pool prices. 151 Transcript Volume 26, Cross-examination of FIRM, page 6126, line 7 to page 6127, line 4. See also Transcript Volume 25, Evidence of ANC/MW, page 5884, line 17 to page 5885, line 12.
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To clear up any confusion that may have arisen during the proceeding, UNCA reiterates that the unadjusted Pool Price Deferral Account was calculated with the Option G energy volumes included. Given that the Option G customers paid actual pool price for their consumed energy, the Option G adjustment therefore removes the energy and the associated actual to forecast pool price variance (-$68.3 million) from the deferral account. Conversely, on an actual basis, Option G customers received higher GAC credits which were derived from actual pool prices that were substantially higher than forecast. Consequently, this actual to forecast GAC credit variance ($87.6 million) was added back to the deferral account. Like the DAT adjustment, the alternate approach that could have been used for the calculation of the Option G adjustment would have been to exclude the Option G volumes in the initial unadjusted Pool Price Deferral Account determination, and simply add the difference between the actual and forecast GAC credits.
The net effect of these two components is the Option G adjustment and is an increase to the pool price deferral account of $19.24 million, as shown on Schedule 2.3152.
While the Option G adjustment was questioned, by IPCCAA153, it is UNCA’s submission that the concern was primarily related to allocation issues, which are addressed in Section 5.2.
UNCA submits that the Option G adjustment is a pool price dependant variance and appropriately reflects the structure and purpose of the basic pool price deferral formula: i.e. to capture 100% of the price variance at actual volumes. UNCA is generally aware of the main elements that were documented that lead to the design of Option G prior to 2000, but does not consider them relevant to the particular issue of allocating the pool price deferral account for 2000.
UNCA Response to IPCCAA UNCA disagreed with IPCCAA’s statement, “But one thing stands out – none of these calculations determine an appropriate level of allocation to Option G loads”154 UNCA noted that it had proposed that the appropriate level of allocation to Option G loads is the same unit level of allocation to Rate 6300-6500 for the first eight months of 2000. UNCA has described this calculation in response to Information Request FIRM.UNCA DISCO-13(c-d).
UNCA noted that IPCCAA proposes the revenue component (in the “bottom up” approach) for Option G should be adjusted by the $19.4 million found on Schedule 2.4, instead of the 12.5 million used by UNCA. IPCCAA bases this on its claim that “the amount by which the GAC credits exceeded the calculated Pool Price deferral is the refund of the hedge value in respect of curtailed load.” This interpretation is irrelevant if UNCA’s intent to establish the deferral account rider to equate to rates that would have resulted had the total costs for 2000 energy been known at the time the rates were set is appropriate. Given that on a forecast basis Option G was designed to be revenue neutral with Rates 6300-6500, it is simple to derive what the revenue (from the bottom up) would have been for Option G consumption:
152 Exhibit 312. 153 Exhibit 908 - IPCCAA Opening Statement. 154 IPCCAA Argument, p. 43
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Pool Price $31.2 (hourly forecast pool price x actual hourly load from BR.UNCA DISCO-1(a-b)) H-factor $–7.8 (0.67 ¢/kWh x actual Option G kWh) Forecast Revenue $23.4
This reconciles with UNCA’s approach that “backed into” the revenue adjustment of $12.5 million to result in the same rider as Rates 6300-6500. In other words, UNCA could have calculated the forecast revenue on Rates 6300-6500 as shown above, instead of “plugging” the $12.5 million, and come to virtually the same result:
Actual Revenue $10.6 (Schedule 8-C Rev 1, April 24) Proposed Revenue Adjustment $12.5 (Schedule 8-C Rev 1, April 24) Calculated Revenue $23.1 (Schedule 8-A Rev 1, April 24)
Thus, UNCA’s proposal is not baseless; it is just not done on the basis proposed by IPCCAA.
UNCA submitted that IPCCAA’s suggestion that UNCA is proposing Option G customers “pay themselves” back the GAC due to curtailed load155 was entirely misleading. Option G customers received the full GAC and nothing in UNCA’s proposal will change that. UNCA submitted that the proposed average deferral amount for Option G applies only to the actual energy consumed, not to any notional curtailed load, and therefore there is no retroactive “paying back” or undoing of what was inherent in Option G at the time it was in effect.
UNCA agreed with IPCCAA that UNCA incorrectly included the forecast H-factor of $6.70/MWh in the January and February revenue calculation for Option G156, resulting in a $1.9 million understatement of generation charges to Option G in Schedule 8-C Rev 1. UNCA noted that the error does not affect the deferral amount UNCA allocated to Option G customers, as the final allocation to Option G was determined to be the same unit level allocated to Rates 6300- 6500. For correctness of the record, UNCA proposed to correct this error when refiling its schedules upon finalization of the deferral account balances.
UNCA Response to ANC/WM In regard to ANC/MW argument that the Board does not have the jurisdiction to retroactively increase Option G’s rates, UNCA submitted that the issue being argued is not one of retroactive ratemaking, but rather of cost allocation. The rates in place in 2000 were implemented to recover forecast costs, with a pool price deferral account established by Decision U99099 to recover price variance from forecast. The deferral account remains to be collected, and the Board clearly has authority to determine which customer classes are assigned a share of the deferral account. UNCA recognized that any such assignment could be considered an increase to the amounts paid by customers in 2000.
In regard to ANC/MW argument that TransAlta never intended the deferral account would apply to Option G, UNCA submitted that history does not support such a statement. UNCA noted that
155 IPCCAA Argument, page 44 156 IPCCAA Argument, page 45
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approximately $22.5 million of the 1999 Pool Price and Reservation Payment Deferral Amounts were included in TransAlta’s 2000 Rate Reduction Rider that applied to every rate class (excluding Temporary Energy Rate 6600), but including Option G.
ANC/MW also argued, “to allocate a portion of the deferral account to Option G ignores the fundamental nature of Option G”157 and repeatedly characterized Option G as “a business arrangement between the Option G load and TransAlta”158 and “a negotiated commercial arrangement.”159 UNCA recognized that Option G evolved over several years and that negotiations were involved in the arriving at the form of Option G approved in 1999, but submitted that Option G was a Board-approved and regulated tariff during 2000.
UNCA noted that ANC/MW acknowledges one of the fundamental design features of Option G i.e. “The principle of trying to achieve revenue neutrality was certainly embodied within the decision”160yet suggests this principle should be ignored in their “commercial arrangement.” In fact, they suggest that only if they ignore this principle would “the parties [have] lived with the conditions they had established.”161
ANC/MW further suggests, “it would be fundamentally unjust and unreasonable to effectively change the economics that were in place over the first eight months of 2000 when they have no opportunity to revisit the decisions that were made at that time and likely would have made different decisions had different economics been in place.”162 Yet in cross-examination ANC/MW stated they likely would not — or could not — have changed their decisions. ANC/MW stated the following:
And if we knew everything that we know now about the year 2000, what more would we have offered so that we would have cut deeper in our operations?163
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157 ANC/MW Argument, page 7 158 ANC/MW Argument, page 12 159 ANC/MW Argument, page 13 160 Transcript, page 5851 161 ANC/MW Argument, page 12 162 ANC/MW Argument, page 12 163 Transcript, page 5886
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APPENDIX 6 - VIEWS OF THE PARTIES RESPECTING PPDA ALLOCATIONS TO RATE CLASS (Click here to return to the text referring to Appendix 6) (Click here for Quick Hyperlinks to sections and material in this Decision and past and current Board Decisions.)
1.1 Views of UNCA UNCA submitted that the bottom-up approach, which allocates costs in a manner consistent with Decision U99035, is the preferred option as it allocates costs in accordance with a methodology approved by the Board after considerable debate and thought. The top-down approach, as discussed during the hearing and filed by UNCA as Exhibit 279, in UNCA’s view, ignores the principles established in Decision U99035 and allocates the deferral account equally to each kilowatt in that hour.
Mr. Martin pointed out that the major difference between the two methodologies is the monthly vs. hourly allocation of unit obligation value (UOV) refunds:
If you just look at what happens to the obligation value refunds moving from a monthly allocation to an hourly allocation, you are very much dealing with marginal costs at that point. And that is the principal element in the allocation that changes, and you are moving from what could be seen as an embedded cost approach to a marginal approach, yes.164
AE’s Mr. Ploof concurs:
I think what the real question gets down to is, how do you allocate the entitlement values?165
UNCA stated that IPCCAA’s Mr. Mikkelson and FIRM’s Mr. Reimer also agree that the significant difference is not top-down vs. bottom-up:
Mr. Mikkelson: “But in terms of the Pool price piece and the UOV piece, with the appropriate revenue treatment, I don't think we would have a problem with it, and I think it would be the same as the top-down approach or very similar.”166 ------Mr. Reimer: “What I have done in this Exhibit 1008 is just drawn data from existing exhibits to try to compare the two approaches that have been labelled the top-down versus the bottom-up approach. And I really think of them more as an hourly approach versus a monthly approach.”167
UNCA noted that the top-down methodology does not require an hourly allocation of UOV refunds. In fact, UOVs could be allocated hourly, monthly, or annually with either a bottom-up
164 Transcript page 4753-4754 165 Transcript page 5080 166 Transcript page 5563 167 Transcript page 6046
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or top-down approach. UNCA notes that it filed the following three methodologies during the hearing:
• Exhibit 314: bottom-up, monthly UOV refund allocation • Exhibit 376: bottom up, annual UOV refund allocation • Exhibit 379: top-down, hourly UOV refund allocation
As stated, the principal element that changes is the UOV refund allocation. Bottom-up and top-down methodologies should produce similar cost allocations, provided the cost components of each were allocated on the same basis — hourly, monthly or annually.
However, as demonstrated in UNCA’s Exhibit 379 top-down allocation with hourly UOV refund allocation, UNCA stated that significant differences result with different UOV refund allocations. UNCA submitted that a monthly UOV refund allocation most closely adheres to the principles underlying the rate design in place during 2000, as stated by Mr. Martin:
We concluded, after much discussion, that we should really try to keep the way the signals, the price signals would flow through to customers the same and limit the retroactivity of what we were doing, really, to the level of prices, not to the underlying structure.
Once we concluded that, that pretty much led us to our bottom-up approach where we said, Okay. Let's take the process we went through in designing the rates that were in effect in 2000 and simply change the level of cost in the various components we were dealing with and see what happens there. And that is what we ended up doing.
The advantages, I think, are that it holds true to the principles that were underlying the rates that we had in place last year. We reviewed the arguments put forth in the original 1996 Phase II application, looked at what came out of that, and said, Yes. Those principles can still apply.
We didn't think that anything that changed the level of cost involved last year would have fundamentally changed the decision which led to the rate design except, perhaps, as we have discussed, the asymmetrical pattern that Pool prices followed where they were extremely high in later months of the year. But fundamentally, we think if we had known in advance what would have actually transpired in 2000, we likely would have reached the same conclusion with respect to cost allocation and rate design.168
In summary, UNCA submits that the choice of bottom-up vs. top-down methodology is less important than the choice of monthly vs. hourly UOV refund allocation, and that a monthly UOV refund allocation is the most appropriate approach.
168 Transcript page 4750-4751
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UNCA replied to the FIRM’s argument as follows.
FIRM appears to equate the “top-down” approach with an hourly allocation of unit obligation value refunds and the “bottom-up” approach with a monthly allocation169. Other parties recognize the top-down vs. bottom-up and hourly vs. monthly allocation as two separate and generally independent distinctions.170
Based on its characterization, FIRM then suggests, “The top-down approach is superior to the bottom-up approach for numerous reasons.”171 UNCA offers the following comments on FIRM’s “reasons”:
• Precise: The top-down and bottom-up methods are equally precise (in terms of exactness), as each use the same hourly and monthly values in the allocation methodology. • Accurate: The accuracy of a method can only be assessed against a standard of truth or correctness. FIRM is therefore simply stating that it considers “top-down” to be the correct approach. • Simple: UNCA submits neither method is particularly simple, as both depend on hourly load values and hourly pool prices for a variety of rate classes. FIRM also suggests that customers were “exposed” to deferral accounts during 2000. UNCA submits that had such exposure actually occurred during 2000, there would be no need for a process to determine how those accounts should be allocated. • Fair: Once again, with standards of rules or correctness not yet established (other than, in UNCA’s opinion, those set out in Decision U99035) FIRM is again simply stating that it considers “top-down” to be the fair approach. • Masking of Pool Price Signals: FIRM identifies the concern “that customers, who consumed less energy during periods of high hourly Pool prices, should benefit from that consumption pattern.”172 This presumably means that customers with relatively flat load profiles should be allocated a proportionately smaller share of the deferral account than customers with load profiles that peak during high pool price hours. UNCA concurs, and submits that a monthly (rather than hourly) allocation of obligation value refunds achieves such an allocation. • Incremental Costing: FIRM correctly describes the top-down approach as treating forecast costs and deferral account costs separately and differently, and the bottom-up approach as treating both costs similarly.173 UNCA submits that the principles underlying Decision U99035 did not distinguish between forecast costs and
169 FIRM Argument, page 60 170 e.g. see ATCO Argument, page 21 and IPCCAA Argument, page 37 171 FIRM Argument, page 61 172 FIRM Argument, page 65 173 FIRM Argument, page 67
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“market fluctuations coupled with unhedged purchases,” but simply established a single methodology for the allocation of energy supply costs. • Embedded Cost Rate Design: FIRM suggests “the results of a bottom- up approach may have violated Board directions from previous decisions” and “the bottom-up approach of rate design based on Board directives for the year 2000 may yield different results than using the bottom-up approach for the purpose of allocating the 2000 Distribution Pool Price Deferral Account.”174 UNCA submits both top-down and bottom-up approaches are subject to these considerations, and in particular the specific points raised by FIRM of the 10% limit to overall increase in revenue by rate class, levels of generation charges and time-of-use differentials, and impacts on customer decisions to use energy. • Impact on Customers: FIRM restates its recommendation offered in its “Masking of Pool Price Signals” comments: “the suitable allocation methodology should reward those consumers that helped…by reducing energy consumption, or by having a load profile whereby less energy is consumed during periods of high Pool price.”175 UNCA again submits this means that consumers with relatively flat load profiles should be allocated a proportionately smaller share of the deferral account than customers with load profiles that peak during high pool price hours, and that a monthly (rather than hourly) allocation of obligation value refunds achieves such an allocation. 176
Given the above responses to FIRM’s criteria, UNCA submitted its allocation methodology is certainly not inferior to other methodologies, but rather it is the appropriate methodology to use in these circumstances.
1.2 Views of AE DISCO AE DISCO’s deferral allocation method was characterized as a “Top Down” approach during the hearing. This approach looks at hourly deferral account accumulations and apportions these costs to rate classes based on fixed price energy use during that hour.
UNCA’s deferral allocation method was characterized as a “Bottom Up” approach during the hearing. It takes actual 2000 Power Purchase Costs, Power Purchase Entitlements, and Reservation Payments, and allocates costs and redesigns rates using these input criteria. It then determines the difference between what a rate class pays on the redesigned rates with what the rate class actually paid on actual rates. The discrepancy by rate class is then used to apportion out the deferral account.
174 FIRM Argument, page 68 175 FIRM Argument, page 69 176 UNCA Reply Argument, page 21
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AE stated that it should be noted that AE DISCO, in its top down method, allocated the entitlement deferral account on an hourly basis, while UNCA allocated it on a monthly basis. However, AE stated that this is not the fundamental difference between the two approaches (26T6126). Either method can be done using either monthly or hourly allocation of entitlement values and has been done by both AE DISCO (Ex. 440) and UNCA (Ex. 379).
AE stated that the difference between the two methods is whether or not the hourly deferral amounts only are allocated using the characteristics of that hour, (the AE DISCO approach), or whether the actual final costs to a rate class are compared to what the rate class actually paid during 2000, and the difference by rate class used to allocate the deferral amounts (the UNCA approach).
During testimony, AE DISCO indicated that it did not think the UNCA approach was valid for use by AE DISCO (23T5076). The major reason was because AE DISCO's rates in effect from April 2000 onwards were designed on a bundled basis, with a 10% rate cap in place for 3 of its rate classes to avoid rate shock (23T5078). As such, these rate classes did not recover 100% of the costs allocated to them.
Therefore, while AE DISCO felt that it could go back in time and allocate costs by rate class in a method similar to UNCA’s, it could not realistically redesign its rates using a similar approach to that used in the original design (with respect to rate shock considerations on a bundled rate basis), and therefore achieve a reasonable allocation of the deferral account (23T5079).
AE noted that it was suggested by the IPCCAA witness (24T5563) that the two approaches would yield similar results if the entitlement deferral amounts were allocated in the same fashion. This is further confirmed via inspection of Exhibits 379 and 440. AE noted the shift in costs from Industrial customers to Residential and Commercial customers when a monthly allocation of entitlement values is used.
As such, AE DISCO still has the position that each DISCO should be able to proceed with their desired approach, as advocated by the AE DISCO witness (23T5081). It is up to the Board to decide if the entitlement deferral allocation method (i.e. either hourly or monthly) should be standardized.
AE DISCO responded to IPCCAA’s claim that IPCCAA had not seen any “argument presented as to why either the top down or bottom up allocation could or should not be adopted by AE DISCO.”177
A simple review of the Hearing Transcript (23T5076, 23T5078, 23T5079) and of AE DISCO’s Argument in Chief reveals that AE DISCO has extensively put forth its reasons for not using the “Bottom Up” approach on the record during both testimony and argument. AE DISCO reviewed its reason for not using the “Bottom Up” approach as follows.
The rate design of the 98GTA rates incorporated a 10% rate cap. AE stated that this cap affected three rates, such that less than 100% of their costs were recovered on a forecast basis.
177 IPCCAA Argument page 42
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As such, AE DISCO stated that, while it could allocate costs to rate classes based on 2000 actuals, it could not design rates in the same manner as the original rates, due to this rate cap, and still allocate the deferral account in a equitable manner. Essentially what would happen is that the three capped rate classes would see none of the extra costs. As such, AE DISCO moved forward with its “Top Down” approach.
As indicated in the comparison of the AE DISCO and UNCA approach to allocation, AE stated that an hourly or monthly allocation of entitlement deferral can be used in either approach. AE stated that the question to be decided by the Board is if the method of entitlement is to be standardized, which allocation method should be utilized.
In Exhibit 440, AE DISCO showed the results of its allocation method using both the hourly and monthly approach to allocate entitlement deferrals. AE noted that the allocation results by rate class differ significantly. Most noticeable are the increases to the Residential (66%) and Commercial Rate Classes (119%), and the decreases to the Industrial T-connect (-28% on average) and D-connect (-17% on average) Rate Classes, when the entitlement deferral is allocated on a monthly basis.
AE noted that Street Lighting and Private Lighting combined also benefit from a monthly entitlement allocation such that they are entitled to $0.3M instead of owing $0.3M. This is a directionally similar result to what UNCA arrived at for exterior lighting (21T4518).
In Decision U99034, AE stated that AE DISCO was directed to allocate the difference between its forecast entitlement and forecast reservation payment across all forecast energy, to derive an H-credit, which was to be refunded to customers. AE stated that IPCCAA has taken this directive as an indication that the difference between forecast and actual entitlement in a month, as contained in the deferral formula respecting entitlements, should also be spread evenly across all energy consumed in that month, in order to avoid masking the pool price signal (24T5565). Given the dramatic reduction in the deferral amount allocated to their rate class using this method, AE stated that it is not surprising that they are pursuing this approach.
Notwithstanding the disconnect between the form of the H-credit from U99034 and the form of the Entitlement deferral account, AE DISCO stated during the hearing (23T5077) that it did not consider the conditions which unfolded during 2000 with respect to actual pool price values and entitlement values were those envisaged by the Board when it developed the H-credit formula. AE DISCO believes that had the Board known of the magnitude of hourly fluctuations, which were to occur with pool price in 2000, and by association hourly entitlement amounts, that they may have chosen to allocate these forecast values in a different manner. Unfortunately, at the time of the directive, pool prices were envisaged to be in the range of $30-$40/MW.h and the accompanying forecast entitlement amounts correspondingly relatively flat by hour.
ATCO Electric maintained that if entitlement values are allocated on a monthly basis, basically what is occurring is that rate classes will be charged for energy use based on their actual hourly load profile (which is subject to massive fluctuations in pool price), but will be refunded entitlements on a relatively flat (monthly) load profile (a yearly allocation of entitlement values would be a completely flat profile). AE stated that this approach would only work if the
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entitlements were accumulated in relatively flat fashion on an hourly basis (relatively independent of pool price), as would have occurred had pool prices been stable around the $40/MW.h forecast pool price for 2000. Unfortunately, this was not the case during 2000.
Pool Price averaged over $130/MW.h during 2000, with over 2800 of the 8784 hours reporting a pool price of $100/MW.h or more, and over 400 hours reporting a pool price of $500/MW.h or more. As a result, the pool price, and by extension, entitlement profile during 2000 fluctuated significantly depending on the hour in question. It is for this reason that ATCO Electric maintained that the entitlement value for any hour is properly allocated based on proportion of fixed price energy consumed by each rate class during that hour.
AE stated that an analogy might serve to illustrate the need for hourly allocation of entitlement values.
Two salesmen are being compensated by their employer based on the number of hot dogs they have sold during a day. Due to supply and demand constraints, they can sell the hot dogs for earnings of 1$/hot dog during 23 hours of the day and for $100/hot dog during the noon hour. The first salesman sells 1 hot dog during each of the 24 hours, generating $123 (23*$1+1*$100) of earnings. The second salesman sell 24 hot dogs, all of them during the noon hour. As a result, he generates $2400 (24*$100) of earnings.
So in total the two generate a total of $2523 in earnings, on sales of 24 hot dogs each (48 in total for the two).
So if they are compensated based on a per hot dog basis, each will receive $1261.50 ($2523/48 hot dogs = $52.56/ hot dog * 24 hot dogs).
But if they are compensated based on the number of hot dogs they sell in an hour times the earnings/hot dog for that hour, the first salesman would receive $123, and the second salesman would receive $2400.
The salesmen’s earnings in this analogy are representative of entitlement values. These two salesman must also pay rent to their employer for their hot dog stands on an hourly basis during the day. These costs are 2$/hotdog for 23 hours of the day, and $200/hot dog during the noon hour. Their employer does not average these rents across the total number of hot dogs sold by the two, but instead collects them based on the actual hours in which they sold the hot dog.
Therefore, the first salesman pays $246 in rent to his employer (2$ * 23 hot dogs + $200 * 1 hot dog), while the second salesman pays $4800 in rent to his employer ($200 hot dog * 24 hot dogs).
The salesmen’s rents in this analogy are representative of pool price.
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So if the salesmen are compensated based on a per hot dog basis, ignoring the hour in which the hot dog was sold, their net situation looks as follows:
Salesman 1 Earnings: $1261.50, Rent: $246 Salesman 2 Earnings: $1261.50, Rent: $4800
But if the salesmen are compensated on a per hot dog basis based on the hour in which they sold the hot dogs, while they both should consider career changes, their overall situation is far more equitable, as follows:
Salesman 1 Earnings: $123, Rent: $246 Salesman 2 Earnings: $2400, Rent: $4800
ATCO Electric maintained that allocation of entitlement values on an hourly basis is more equitable to its customers, due to the magnitude of hourly pool price and entitlement fluctuations, which occurred during 2000.
AE submitted that IPCCAA without being aware of it, in their Argument, violently agreed with AE that pool price fluctuations in 2000 make the use of anything but an hourly allocation of entitlement value unworkable. AE demonstrated the significant fluctuations that occurred in hourly pool price during 2000 and IPCCAA echoed the same concern about these fluctuations, albeit on a seasonal (monthly) basis, to support moving away from an annual allocation of entitlement values to a monthly approach saying:
Specifically, the seasonal variations in Pool Price in 2000 were dramatic (emphasis added). The difference between the highest and lowest average monthly price exceeded $200/MWh. The 1998 Pool Price record, that formed the basis for 2000 rates, saw the difference between the highest and lowest average monthly price of less than $27/MWh.
AE maintained that if these pool price variations were “dramatic” on a seasonal basis – then these fluctuations must be labeled as “severe” on an hourly basis. As the analysis of pool price fluctuation in the AE’s Argument demonstrated more than 400 hours of the 8760 in 2001 saw pool prices above $500/MW.h.
AE maintained that the only fair method to allocate the deferral account balance for the 2000 entitlement values was on an hourly basis.
1.3 Views of IPCCAA IPCCAA noted that two deferral account allocation approaches have been proposed in this proceeding. UNCA has proposed what has been termed a "bottom up" approach and ATCO has proposed a "top down" approach.
IPCCAA noted that the “bottom up” approach compares generation revenues with allocated costs. IPCCAA stated that this approach is consistent with the cost allocation used to determine the rates in place for the last 10 months of 2000. IPCCAA noted that UNCA has allocated Pool
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purchase costs on an hourly basis and the H-factor (Reservation Price less actual UOV refunds) on a monthly basis. GENCO STS adjustments for TAU and ATCO have been included as Reservation Price adjustments.
IPCCAA stated that the “top down” approach allocates the components of the deferral account to rate classes. ATCO’s “top down” approach allocates the Pool Price, Entitlement (UOV) and GENCO components of the deferral account on an hourly basis. IPCCAA stated that it is important to recognize that an hourly allocation is not inherent in the "top down" approach. Each of the components of the deferral account can be allocated on a different basis. IPCCAA’s position is that it is appropriate to allocate the Pool Price component on an hourly basis and the Entitlement (UOV) component on a monthly basis.
UNCA has incorporated all deferrals (Pool Price, UOV, GENCO generation and ancillary service, GENCO STS and other reservation price adjustment) in one step. This precludes examination of the allocation of the various components of the deferral accounts. IPCCAA submitted that there is a logical basis for examining each component of the deferral accounts individually and determining an appropriate allocation methodology. IPCCAA addressed the allocation of the following components of the pool price deferral account:
a) Pool Purchases Component b) Entitlement UOV Component
(a) Pool Purchases Component
IPCCAA stated that no party to this proceeding has proposed anything other than an hourly allocation of Pool Price components of the deferral accounts (either through the bottom up or top down methodology). IPCCAA stated that clearly those loads that were higher during periods of high pool prices should carry a larger share of the pool purchase cost. An hourly allocation of pool purchases (or pool purchased deferral) will accomplish this.
IPCCAA stated that such allocation is consistent with the Board’s finding in U99035.
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. (U99035 p. 22)
IPCCAA stated that the Pool Price allocation should reflect the interaction of rate class load profile with the pattern of Pool Prices. In the case of UNCA, the weighted average Pool Purchase Cost (cost of purchases at actual Pool Price, with no legislated hedges) by rate class was:
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Table 8: UNCA Average Pool Purchase Cost by Class (per IPCCAA) Average Power Pool Purchase Cost $/MWh Difference Rate Class Rate Avg from Avg PP Description Code $/MWh $/MWh Residential 11XX–12XX 145.51 +12.29 UNCA Farm 21XX–23XX 137.78 +4.56 REA Farm 24XX–25XX 135.92 +2.70 UNCA Irrigation 26XX–27XX 115.13 N/A REA Irrigation 28XX–29XX 120.71 N/A Exterior Lighting 3XXX 107.52 -18.09 Small General Service 41XX–43XX 151.14 +17.92 Pumping 44XX–46XX 133.36 +0.14 General Service 61XX–62XX 139.88 +6.66 Large General Time- 63XX 135.39 +2.17 of-Use Direct Connected 65XX 133.56 +0.34 Service Option G (Jan-Aug) Option G 85.87 N/A Wholesale Service 81XX 146.82 +13.60 (Closed) Source: Exhibit 913 Tab: 8-D Purchases divided by 8-G Energy
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IPCCAA noted that the variation between rate classes is significant. For example, Small General Service had an average purchase cost $18/MWh higher than Direct Connected loads (and also $18/MWh higher than the annual average Pool Price of $133/MWh).
IPCCAA stated that this variation in Purchase costs is the Pool Price signal that should be preserved in the allocation of the legislated hedges.
(b) Entitlement (UOV) Component
IPCCAA noted that various positions have been put forth as to the appropriate allocation of the UOV component of the deferral accounts: UNCA proposed a monthly allocation (through their bottom up approach), AE and the FIRM group an hourly allocation (through the top down approach) and AIPA appears to support an annual allocation.
Annual UOV Allocation IPCCAA stated that there is no question that the rates implemented on March 1, 2000 incorporated an annual allocation of UOV refunds (a reservation price). Further, IPCCAA stated that there is also no question that the DATs approved for both UNCA and ATCO charged or
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refunded a UOV component based on the monthly variance of DISCO entitlements from “forecast” (in this case, 1998 actual results).
IPCCAA stated that the principles underlying the appropriate allocation of UOV, whether the entire UOV (in the bottom up allocation) or the incremental or deferred UOV (in the top-down allocation) were presented in U99035.
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 maximum incentives for efficient behavior on both the supply and demand sides of the market. (U99035 p. 23, emphasis added)
IPCCAA stated that the Board found in U99035 that an allocation of UOV (and RP) on an annual basis would satisfy the principle of not interfering with the Pool Price signal. IPCCAA stated that circumstances in 2000 have differed in a manner that would make an annual allocation unworkable. Specifically, the seasonal variations in Pool Price in 2000 were dramatic. The difference between the highest and lowest average monthly price exceeded $200/MWh. The 1998 Pool Price record, that formed the basis for 2000 rates, saw the difference between the highest and lowest average monthly price of less than $27/MWh.
IPCCAA stated that the main inequity arising from the use of an annual UOV refund would be the treatment of Option G loads. These loads were Option G for the first 8 months of the year and DAT for the remainder. IPCCAA stated that to pay UOVs on an annual basis to Option G loads where they have already received monthly UOV refunds in respect of the last four months of the year on the DAT would be “double refunding” for the last four months. In fact, an annual allocation of UOV refunds (combined with an hourly allocation of Pool Price deferrals) would require a refund to Option G loads of $33 million (Hourly Pool Price allocation from Ex 914, UOV refunds allocated on the basis of annual energy).
IPCCAA stated that significant adjustments would be required to equitably implement an annual UOV allocation. No such adjustments have been proposed in this proceeding.
Furthermore, IPCCAA noted that annual allocations result in a deferral account allocation of $610,000 to irrigation (Hourly Pool Price allocation from Ex 914, UOV refunds allocated on the basis of annual energy). Based on a usage of approximately 225,000 MWh, this equates to less than $3/MWh. Approximately ½ of the irrigation load was in August, a month with an average Pool Price of approximately $200/MWh. Given that the UNCA DISCO was roughly 10% unhedged in August, (UNCA unhedged load, from BR-UNCA-1, averaged 12% for all hours and averaged a minimum of 10% in each hour over the month), IPCCAA stated that this would give rise to a $20/MWh ($200/MWh x 10%) deferral component to irrigation load in August or
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$10/MWh over the total annual load. Clearly, IPCCAA stated that an annual UOV allocation does not provide a reasonable deferral allocation to irrigation load.
Monthly UOV Allocation IPCCAA noted that the significant variation in monthly Pool Prices gave rise to the distortions created in the annual allocation. Monthly UOV allocations have been proposed by UNCA and IPCCAA. IPCCAA stated that use of monthly allocations would address inequities arising from annual allocations to seasonal loads. Monthly UOV refunds were incorporated in the DAT specifically to address significant variation in Pool Prices:
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).178
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:179
Adjustment = (billing month’s total actual DISCO UOV refund – 1998 month’s total DISCO UOV refund)/ 1998 DISCO monthly energy use
While the preceding excerpt speaks of DAT customers being no worse off than customers on fixed rates, IPCCAA stated that the converse is now also important. IPCCAA stated that the allocation of the deferral accounts should not leave fixed rate customers better off than had they been DAT loads. Through the deferral accounts all customers have, to a degree, become actual pool price DAT customers.
178 Decision U99035, page 120 179 Decision U99035 page 120-121
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Hourly UOV Allocation The following table demonstrates the difference between an hourly and monthly UOV refund. The table takes the amount allocated by rate class (from Exhibit 914) and divides it by the annual rate class energy. (Schedule 8-G).
Table 9: Difference between an hourly and monthly UOV refund (Per IPCCAA) Allocation of Pool Price plus UOV Refund Hourly and Monthly UOV Allocation ($/MWh) Top Down Hourly PP and Top Down Hourly Rate Class Rate Hourly UOV PP and Monthly Description Code Allocation UOV Allocation Residential 11XX–12XX 19.6 26.9 UNCA Farm 21XX–23XX 18.7 21.7 REA Farm 24XX–25XX 18.4 21.4 UNCA Irrigation 26XX–27XX 15.4 13.4 REA Irrigation 28XX–29XX 16.1 14.0 Exterior Lighting 3XXX 16.2 (7.6) Small General Service 41XX–43XX 20.3 30.8 Pumping 44XX–46XX 18.4 15.7 General Service 61XX–62XX 19.1 20.9 Large General Time-of-Use 63XX 18.6 17.5 Direct Connected Service 65XX 18.3 15.7 Direct Access Tariff 68XX N/A N/A Option G Option G 10.6 3.2 Wholesale Service (Closed) 81XX 19.8 27.7 Total UNCA — $17.9 $17.9
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IPCCAA stated that it can be readily seen that the hourly Pool Price and hourly UOV allocations, together, virtually eliminate the differentials in rate class average Pool purchase costs. In the language of U99035, IPCCAA stated that the hourly allocation diminishes the strength of the connection between market-determined prices and customer behaviour.
There is a need at this time to align the emerging system with the requirements of a competitive marketplace. That requires that both RP and UOV be allocated based on energy use and in a manner that ensures they do not diminish the strength of the connection between market-determined prices and customer behaviour.180
180 U99035 page 23
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IPCCAA stated that the monthly UOV allocation, on the other hand, preserves the Pool Price signal. IPCCAA stated that the differentials by rate class are much more consistent with the differences in Average Power Pool Purchase Cost. (Pool Purchases with no hedges)
To confirm that the distortion in relative allocation between rate classes is introduced by the hourly UOV allocation, and not the Pool Price allocation, IPCCAA looked at the two components separately.
Table 10: Hourly Allocation of Pool Price and UOV Refund (Per IPCCAA) Hourly Allocation of Pool Price and UOV Refund ($/MWh) Rate Class Rate Hourly PP Hourly UOV Hourly PP and Description Code Allocation Allocation UOV Allocation Residential 11XX–12XX $115 ($95) $20 UNCA Farm 21XX–23XX $108 ($89) $19 REA Farm 24XX–25XX $106 ($88) $18 UNCA Irrigation 26XX–27XX $90 ($75) $15 REA Irrigation 28XX–29XX $95 ($79) $16 Exterior Lighting 3XXX $83 ($67) $16 Small General 41XX–43XX $120 ($100) $20 Service Pumping 44XX–46XX $105 ($86) $18 General Service 61XX–62XX $111 ($92) $19 Large General 63XX $107 ($88) $19 Time-of-Use Direct Connected 65XX $105 ($87) $18 Service Direct Access 68XX $0 $0 $0 Tariff Direct Access 68XX $0 $0 $0 Tariff Option G Option G $59 ($48) $11 Wholesale 81XX $116 ($97) $20 Service (Closed) Total UNCA — $103 ($85) $18 Source: Exhibit 914 Tab: 1 Comparison divided by Schedule 8
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IPCCAA stated that the rate class differentials in allocation of the Pool Price component of the deferrals mirrors closely the rate class differentials shown earlier in the allocation of total Power Pool purchases by rate class.
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IPCCAA stated that the hourly allocation of the UOV component of the deferrals, on the other hand, offset the Pool Price differentials. IPCCAA stated that this is precisely the effect that the Board was trying to prevent in the allocation of hedge in the 1996 Phase II decision.
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.181 (emphasis added)
IPCCAA stated that the hourly allocation of UOV refunds masks the Pool Price signals that the Board considered should be preserved. IPCCAA noted that the signal was preserved for DAT loads through the pass-through of the actual hourly Pool Price and an allocation of the monthly UOV refund.
IPCCAA stated that to adopt an hourly UOV deferral is to grant additional hedges to loads that purchased more of their requirements at times of higher Pool Price. IPCCAA stated that there is no basis to conclude that these loads paid for additional hedges therefore the UOV allocation should not treat them like they did.
For the reasons cited above, IPCCAA submitted that the appropriate treatment for the UOV component of the deferral accounts is a monthly allocation. This can be accomplished either through the top down or bottom up approach.
Does Bottom up equal Top down? IPCCAA noted that Decision 2000-3 established deferral account formulas for TransAlta (now UNCA) DISCO that expressly included two components. IPCCAA noted that the first was intended to capture the difference between actual and forecast Power Pool purchases in respect of hedged load. The deferral amount was to be calculated as:
(Actual pool price – Forecast pool price) x (Actual energy purchases)
IPCCAA noted that the second component was intended to capture the difference between actual and forecast entitlements. The deferral amount was to be calculated as:
(Actual DISCO entitlement – Forecast DISCO entitlement)
IPCCAA reviewed the above components to point out that these amounts do appear in UNCA’s allocation. UNCA calculated the amount of the deferral using these equations (and certain adjustments), but this amount is only used as a target against which to calibrate the shortfall between total revenue and costs where costs are based on the total actual Power Pool purchases, total actual DISCO entitlements and reservation prices.
IPCCAA noted that UNCA adjusted the revenue side, through application of an “across the board” rider (of 0.7% (21T4504)) in order for their bottom up deficiency calculation to equal the
181 U99035 page 23
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amounts derived from the approved formulas; amounts allocated directly in the top down approach.
Comparison of Bottom up and Top-down IPCCAA prepared a comparison of the bottom up and top down allocation methods for the UNCA DISCO (Exhibit 913). Adjustments were made to the UNCA filing to remove GENCO related items, resulting in a comparison of the allocation of only the pool purchase and UOV refund components. The GENCO related items can be considered separately and removing them from the comparison provides for more of an “apples to apples” comparison. The following table presents the total dollars allocated to each rate class. Note that the “Bottom up” calculation incorporates changes to remove the GENCO related items (GENCO Deferrals and RP adjustments) and also incorporates the adjustments proposed by IPCCAA to exclude DAT loads from the allocation as well as proposed changes to the Option G revenue filed by UNCA.
Table 11: IPCCAA Comparison Pool Price and UOV Components Only IPCCAA comparison of Bottom up and Top down UNCA Allocation Pool Price and UOV Components Only $ 000’s Top down Bottom up Hourly PP and UNCA with Monthly UOV Rate Class Description Rate Code adjustments Allocation Residential 11XX–12XX $54,950 $54,554 UNCA Farm 21XX–23XX 13,858 13,583 REA Farm 24XX–25XX 10,181 10,221 UNCA Irrigation 26XX–27XX 1,605 3,028 REA Irrigation 28XX–29XX 10 23 Exterior Lighting 3XXX (243) (529) Small General Service 41XX–43XX 31,881 32,657 Pumping 44XX–46XX 12,865 12,761 General Service 61XX–62XX 109,061 110,487 Large General Time-of-Use 63XX 50,689 48,962 Direct Connected Service 65XX 143,164 141,117 Direct Access Tariff 68XX 0 0 Option G Option G 2,570 3,706 Wholesale Service (Closed) 81XX 3,172 3,194 Total UNCA — $433,763 $433,762 Source: Ex 914 Tab Comparison
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The table below presents the amounts on a unit basis.
Table 12: IPCCAA Comparison Pool Price and UOV Components (Per Unit) IPCCAA comparison of Bottom up and Top down UNCA Allocation $/MWh Average Power Top down with Pool Purchase Rate Class Bottom up with Hourly PP and Cost less Avg Description Rate Code Adjustments Monthly UOV PP Residential 11XX–12XX $27.12 $26.93 +12.29 UNCA Farm 21XX–23XX $22.12 $21.68 +4.56 REA Farm 24XX–25XX $21.30 $21.39 +2.70 UNCA Irrigation 26XX–27XX $7.11 $13.41 N/A REA Irrigation 28XX–29XX $6.27 $13.98 N/A Exterior Lighting 3XXX ($3.49) ($7.59) -18.09 Small General 41XX–43XX $30.08 $30.81 +17.92 Service Pumping 44XX–46XX $15.78 $15.65 +0.14 General Service 61XX–62XX $20.63 $20.90 +6.66 Large General 63XX $18.17 $17.55 +2.17 Time-of-Use Direct Connected 65XX $15.90 $15.67 +0.34 Service Direct Access 68XX N/A N/A N/A Tariff Option G Option G $2.22 $3.20 N/A Wholesale 81XX $27.48 $27.67 +13.60 Service (Closed) Total UNCA — $17.91 $17.91 Source: Exhibit 9 Tab Comparison divided by Schedule 8-G Energy.
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IPCCAA noted that the allocation results are consistent with the differences from Average Power Pool Purchase Cost. For example, Small General Service has an allocation approximately $14/MWh higher than Direct Connected Service or Pumping ($30/MWh less $15-16/MWh) and an average Pool Purchase costs $17-18/MWh higher.
IPCCAA noted that Irrigation is difficult to interpret on an annual basis because the load is treated largely as a flat load shape with a different demand level each month. Therefore, on a monthly basis, they are allocated pool purchases at the average monthly Pool Price.
As described in Exhibit 913, Irrigation may differ between the two methodologies for a couple of reasons. Firstly, only the bottom up, with its revenue calculation) recognizes that irrigation had a higher energy rate than other rate classes. IPCCAA stated that this should suggest a lower
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allocation, perhaps a few $/MWh. Secondly, the monthly deferral under the bottom up approach is lower in the months when irrigation load is present.
As also described in Exhibit 913, IPCCAA noted that Option G sees a lower allocation under the bottom up approach (with IPCCAA’s proposed adjustments) than the top down approach. Similar to irrigation, there would have been a revenue effect for Option G. The January to August period included 5 summer months, with the accompanying higher average rate and 3 winter months with a lower rate. This revenue effect would have reduced the bottom up allocation. Further, as discussed later, the proposed revenue adjustment for Option G for January and February appears to arise from an inappropriate application of the $6.70/MWh H-factor to the revenue calculated for those months. In Exhibit 913 this adjustment, estimated by looking at the unit revenue of Rates 63XX and 65XX, was estimated at $2.7 million. Based on the $6.70/MWh H-factor the adjustment would only be $1.9 million. Such an adjustment would increase the Option G deferral from the bottom up approach from $2.57 million to $3.4 million, very nearly equal to the top down approach allocation of $3.7 million.
IPCCAA noted that UNCA proposed the use of the bottom-up allocation methodology, recognizing that it is of secondary importance to the approach to allocating the UOV component of the deferral accounts.
In summary, UNCA submits that the choice of bottom-up vs. top-down methodology is less important than the choice of monthly vs. hourly UOV refund allocation, and that a monthly UOV refund allocation is the most appropriate approach. (UNCA Argument, Page 45)
IPCCAA noted that UNCA went further to suggest the results from both the top-down or bottom-up allocations should be similar:
Bottom-up and top-down methodologies should produce similar cost allocations, provided the cost components of each were allocated on the same basis — hourly, monthly or annually. (UNCA Argument, p. 44)
IPCCAA agreed that the bottom-up and top-down methodologies should produce similar cost allocations, provided cost components are allocated on the same basis. IPCCAA has shown such equivalence (IPCCAA Argument, Pages 39-41), but the equivalence is only achieved in respect of Option G when IPCCAA’s recommended changes to Option G revenue are made.
AE DISCO stated that the bottom-up approach was not valid for its use:
During testimony, ATCO Electric indicated that it did not think the UNCA approach was valid for use by ATCO Electric. (23T5076)
In suggesting that the bottom-up approach was not applicable to it, IPCCAA noted that AE DISCO brought up the fact that for three rate classes the 1996 Phase II decision placed caps on the increases applied for:
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During testimony, ATCO Electric indicated that it did not think the UNCA approach was valid for use by ATCO Electric (23T5076). The major reason was because ATCO Electric's rates in effect from April 2000 onwards were designed on a bundled basis, with a 10% rate cap in place for 3 of its rate classes to avoid rate shock (23T5078). As such, these rate classes did not recover 100% of the costs allocated to them. (ATCO Argument, Page 21, emphasis added)
IPCCAA stated that AE DISCO apparently did not understand that the bottom-up approach only deals with the energy component of the tariff. The energy component was designed on the basis of a 100% revenue/cost ratio, as directed by the Board.
To ensure some degree of rate stability in moving to accurate cost signals, the Board directs that in the refiling, the DISCO keep any 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. (Decision U99034, Page 40 emphasis added)
IPCCAA noted that AE DISCO suggested that it could not “redesign its rates” because they were bundled and incorporated caps on increases from the previous rates.
Therefore, while ATCO Electric felt that it could go back in time and allocate costs by rate class in a method similar to UNCA’s, it could not realistically redesign its rates using a similar approach to that used in the original design (with respect to rate shock considerations on a bundled rate basis), and therefore achieve a reasonable allocation of the deferral account (23T5079). (ATCO Argument, Page 21, emphasis added)
IPCCAA noted that inexplicably, AE DISCO refers to the 2000 tariffs as “bundled”. IPCCAA noted that looking at the rate schedules in Decision 2000-15, one can see headings of “Energy Supply”, “Transmission” and “Distribution”. These cannot be described as “bundled.
IPCCAA noted that the bottom-up approach compares actual revenue with allocated costs. The bottom-up approach does not require any “redesign” of rates. The revenue is calculated from the energy component of the tariff that was in effect for most of 2000. As described above, the energy component of the tariffs was unbundled and recovered 100% of the energy costs on a forecast basis. On the cost side of the bottom-up approach, AE DISCO’s rate caps do not enter the picture. Pool purchases, UOV refunds and Reservation Price are all allocated on the basis of actual load.
IPCCAA submitted that AE DISCO’s basis, for arguing that the bottom-up approach is not applicable to it, is without merit and may have arisen from the failure of AE DISCO to recognize that the revenue side of the bottom-up approach only relates to the energy portion of the tariff.
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IPCCAA stated that there is no distinction between ATCO Electric and UNCA in terms of being able to utilize the bottom-up allocation approach.
IPCCAA noted that IPCCAA, UNCA, ATCO and AIPA appear to acknowledge that the main allocation issue is the allocation of UOV refunds, specifically whether the allocation should be on a monthly, hourly or annual basis (see UNCA Argument, Pages 43-44).
In its Argument, IPCCAA stated that the FIRM Group preferred to hide behind suspect criteria and to attempt to confuse the Board as to the impact of its proposed allocation methodology on Option G loads.
IPCCAA noted that AE DISCO presents its argument supporting an hourly UOV allocation:
ATCO Electric maintains that if entitlement values are allocated on a monthly basis, basically what is occurring is that rate classes will be charged for energy use based on their actual hourly load profile (which is subject to massive fluctuations in pool price), but will be refunded entitlements on a relatively flat (monthly) load profile (a yearly allocation of entitlement values would be a completely flat profile). This approach would only work if the entitlements were accumulated in relatively flat fashion on an hourly basis (relatively independent of pool price), as would have occurred had pool prices been stable around the $40/MW.h forecast pool price for 2000. Unfortunately, this was not the case during 2000. (ATCO Argument, Page 22, emphasis added)
IPCCAA stated that AE DISCO fails to describe what it means by the emphasized phrase. IPCCAA stated that the phrase implies that it is evaluating the allocation against some criteria, but fails to disclose those criteria and their relevance.
As a result, the pool price, and by extension, entitlement profile during 2000 fluctuated significantly depending on the hour in question. It is for this reason that ATCO Electric maintains that the entitlement value for any hour is properly allocated based on proportion of fixed price energy consumed by each rate class during that hour. (ATCO Argument, Page 22, emphasis added)
IPCCAA submits that the “reason” ATCO Electric puts forward to conclude that an hourly entitlement allocation is necessary is baseless.
IPCCAA provided detailed evidence as to how a monthly UOV allocation properly allocates a portion of the UOV refund from high Pool Price hours to loads that curtailed in response to high Pool Prices (Exhibit 911), whereas an hourly UOV allocation provides no UOV refund in respect of curtailed load.
IPCCAA noted that AE DISCO provided some colour in its argument by offering an analogy that it suggested offered some insight into the allocation of the deferral account components. Unfortunately, its analogy misses the main point – allocation between customers of the right to
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buy at a fixed price independent of market price – that is – allocation of UOV refunds among customers.
IPCCAA has reviewed and analyzed the hot dog analogy set out in the ATCO Electric Argument.
IPCCAA submits that when the analogy is corrected, it properly demonstrates how an hourly allocation effectively allocates a greater share of entitlements for peak hours to on-peak loads. Such an allocation is inconsistent with the allocation of entitlements in the 1996 Phase II where all rate classes were allocated entitlements on the same basis.
To work with ATCO’s analogy, IPCCAA submits the following would be a more appropriate analogy:
IPCCAA’s Corrected “Hot Dog” Analogy 1. Hot dogs are sold at a baseball stadium 24 hours per day. 2. Customers without a coupon expect to pay $5/hot dog in peak times (when games are played) and $2/hot dog in all other hours. 3. There are two customers, A and B. 4. Each customer has coupons allowing him/her to buy hot dogs for $1/hot dog at any time, regardless of the non-coupon price. 5. The coupons must be used in the hour granted and the coupons can be cashed in if not used (the value being the difference between the price in the hour and the “strike price” of the coupon). 6. Both A and B are entitled to the same coupons—4 coupons each peak hour and 3 in each non-peak hour (total 78 coupons each). 7. A consumes 4.5 hot dogs per hour while B consumes 6 hot dogs every peak hour and 4 every other hour (total consumption 108 hot dogs each).
IPCCAA stated that the elements of the analogy are as follows: the price of hot dogs is similar to the Pool Price, the coupons are similar to the entitlements and the consumption patterns are similar to customer load profiles.
IPCCAA stated that the expected costs of the hot dogs, for each customer, are as follows:
Table 13: Expected Average Cost of Hot Dogs (Per IPCCAA) Expected Average Cost $/Hot Dog Customer Customer A B Purchase Cost $2.75 $3.00 Less Coupons (1.39) (1.39) Net Cost $1.36 $1.61
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IPCCAA noted that Customer B has a higher average net cost as a result of buying more hot dogs during peak periods, when the price is higher. But, as both customers have the same number of coupons, regardless of their actual consumption, for each hour, IPCCAA noted that they receive the same coupon refund.
To carry on the analogy, IPCCAA noted that it turns out that the (non-coupon) price of hot dogs was considerably higher than expected. It was $10/hot dog during peak hours and $5/hot dog all other hours. What did the actual cost turn out to be? Recognizing that both customers had the same number of coupons for each hour, the results follow:
Table 14: Actual Average Cost of Hot Dogs With Equal Coupons (Per IPCCAA) Actual Average Cost With Equal Coupons $/Hot Dog Customer Customer A B Purchase Cost $6.25 $6.67 Less Coupons (4.00) (4.00) Net Cost $2.25 $2.67
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IPCCAA noted that the cost of purchases for each customer increased and each customer cashed in the same coupons they had before (although the value of each coupon increased because of the increased price).
If the difference between actual cost and expected cost is captured in a deferral account, and allocated hourly according to actual consumption, IPCCAA noted that the results are different from the table above.
Table 15: Actual Average Cost of Hot Dogs With Hourly Allocation (IPCCAA) Actual Average Cost With Hourly Deferral Allocation $/Hot Dog Customer Customer A B Purchase Cost $6.25 $6.67 Less Coupons (3.93) (4.07) Net Cost $2.32 $2.60
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Through the hourly deferral calculation, IPCCAA noted that Customer B acquires a greater share of the coupon value.
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IPCCAA stated that the calculations shown in Appendix 1 and 2 of its Reply Argument demonstrate that the higher unit coupon value for Customer B arises from the hourly calculation allocating more coupons to Customer B in the on-peak periods (to coincide with actual on-peak consumption) in exchange for allocating more coupons to Customer A in the off-peak periods. As the on-peak coupons are more valuable, the hourly allocation provides higher coupon refunds to Customer B.
Effectively, IPCCAA stated that the hourly allocation provides Customer B with more on-peak coupons (entitlements) because Customer B has more on-peak consumption.
IPCCAA stated that the same effect was shown in IPCCAA’s Argument to result from an hourly allocation of UOV refunds. The following table was presented on Page 29:
Table 16: Hourly Allocation of Pool Price and Monthly UOV Refund (IPCCAA) Hourly Allocation of Pool Price and Monthly UOV Refund ($/MWh) Hourly PP and Monthly Rate Class Rate Hourly PP Monthly UOV UOV Description Code Allocation Allocation Allocation Residential 11XX–12XX $115 ($95) $20 UNCA Farm 21XX–23XX 108 (89) 19 REA Farm 24XX–25XX 106 (88) 18 UNCA Irrigation 26XX–27XX 90 (75) 15 REA Irrigation 28XX–29XX 95 (79) 16 Exterior Lighting 3XXX 83 (67) 16 Small General Service 41XX–43XX 120 (100) 20 Pumping 44XX–46XX 105 (86) 18 General Service 61XX–62XX 111 (92) 19 Large General Time-of- 63XX 107 (88) 19 Use Direct Connected 65XX 105 (87) 18 Service Direct Access Tariff 68XX 0 0 0 Option G Option G 59 (48) 11 Wholesale Service 81XX 116 (97) 20 (Closed) Total UNCA — $103 ($85) $18 Source: Exhibit 914, Tab 1 Comparison divided by Schedule 8
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In this table, IPCCAA noted that the average coupon, or unit UOV refund, resulting from an hourly allocation was larger for the on-peak loads, such as Small General Service and Residential, than for the flatter loads, such as Large General Service. This demonstrates a greater share of the on-peak entitlements being allocated to on-peak loads through an hourly allocation.
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By contrast, a monthly UOV allocation provides the following results:
Table 17: Hourly Allocation of Pool Price and Monthly UOV Refund (IPCCAA) Hourly Allocation of Pool Price and Monthly UOV Refund ($/MWh) Rate Class Hourly PP and Rate Hourly PP Monthly UOV Monthly UOV Description Code Allocation Allocation Allocation Residential 11XX–12XX $115 ($88) $27 UNCA Farm 21XX–23XX 108 (86) 22 REA Farm 24XX–25XX 106 (85) 21 UNCA Irrigation 26XX–27XX 90 (77) 3 REA Irrigation 28XX–29XX 95 (81) 14 Exterior Lighting 3XXX 83 (91) (8) Small General Service 41XX–43XX 120 (89) 31 Pumping 44XX–46XX 105 (89) 16 General Service 61XX–62XX 111 (90) 21 Large General Time-of- 63XX 107 (89) 18 Use Direct Connected 65XX 105 (89) 16 Service Direct Access Tariff 68XX 0 0 0 Option G Option G 59 (56) 3 Wholesale Service 81XX 116 (89) 28 (Closed) Total UNCA — $103 ($85) $18 Source: Exhibit 914, Tab 1 Comparison divided by Schedule 8- G Energy.
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IPCCAA noted that the monthly allocation effectively treats all loads as if they had an equal share of entitlement refunds, i.e. they all had the same coupons.
IPCCAA stated that the entitlements are very analogous to the coupons in IPCCAA’s “hot dog” analogy, above. Entitlements are defined for each hour and the value is determined by the difference between the market price and a “strike price”. “Unused” entitlements can be cashed in. There are limited numbers of entitlements and there are not enough to cover all consumption.
IPCCAA stated that a result that allocates more (valuable) on-peak entitlements to certain rate classes is not equitable. IPCCAA stated that there is no basis for suggesting that on-peak loads should be granted more of the on-peak entitlements (UOV refunds) than loads with a flat profile. It is IPCCAA’s position that no rate class is entitled to a greater share of the entitlement than any other rate class.
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IPCCAA stated that Decision U99035 allocated the same entitlements to each rate class through the H-factor. The DAT allocated the same share of entitlements to customers from any rate class that took service on the rate, and effectively did so with a monthly allocation of UOV refunds. IPCCAA stated that there is simply no basis to suggest that some rate classes have a right to more entitlements than others.
IPCCAA stated that the following excerpt from the FIRM Group Argument appears to conclude that the deferral account calculations should be based on forecast load:
The Board in Decision 2000-3, states, “The Board considers that it clearly stated in the decision that pool price variance should be covered by deferral accounts and be to the account of customers and that volume variance is not included in deferral accounts and should be to the account of shareholders”. This indicates that the original load forecast is to be used in deferral account calculations. (FIRM Argument, Page 59, emphasis added)
IPCCAA stated that this is clearly in error. Later in the same decision cited, IPCCAA stated that the Board presents the deferral account formula:
Therefore the Board directs that the following formulas be used by TransAlta to determine its deferral accounts.
The formula for the DISCO pool price deferral account:
Pool price deferral = (Actual pool price – Forecast pool price) x (Actual energy purchases) - (Actual DISCO entitlement – Forecast DISCO entitlement)
(Decision 2000-3, Page 12, emphasis added)
IPCCAA stated that the formula could not be any clearer: it reads “actual energy purchases”, not forecast load or forecast purchases.
IPCCAA noted that the FIRM Group then attempts to draw a distinction between actual (hourly) load utilized in the deferral account calculations and “forecast based load profiles” for customers without interval meters.
Therefore, the practical approach is to use the actual hourly load for 2000 for those customers that have interval recording meter data, and to use forecast based load profiles for those customers that did not have interval recording meter data. (FIRM Argument, Page 61)
IPCCAA stated that no forecast loads were used in the deferral calculations. On page 6 of its Application, IPCCAA noted that UNCA describes the use of actual load data.
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IPCCAA stated that “Why is the FIRM Group bringing up this incorrect interpretation of the deferral account formulas?” To begin with, IPCCAA stated that it raises a valid point with respect to the problems that would be caused by utilizing rate class forecast load:
Large consumers are generally sophisticated and may have had the ability to control their costs by reducing load during periods of high hourly Pool prices. Those customers that did respond to high hourly Pool prices should be assigned a lesser amount of the 2000 Distribution Pool Price Deferral Account, in accordance with their reduced energy consumption. The use of forecast load (that did not consider curtailment resulting from high prices) would mask pool price, and would claw back any benefits of load curtailment by that particular customer. (FIRM Argument, Page 59, emphasis added)
IPCCAA noted that the FIRM group suggests that the use of forecast load to allocate deferral amounts would be inappropriate (as it would be, especially in the case of the Pool Purchase component). IPCCAA stated that the FIRM Group’s intention for raising such a non-existent distinction becomes clear in the following passage:
The customers that reduced load in response to pool price should retain the benefit of their actions (V26, P6118, L1-17). In order to ensure that these benefits are not clawed back, the actual hourly energy consumption must be used, along with the hourly formula for calculating the 2000 Distribution Pool Price Deferral Account. (FIRM Argument, Page 61, emphasis added)
IPCCAA stated that the FIRM Group acknowledges that customers who curtailed loads in response to Pool Price should be entitled to “retain the benefits of their actions”. IPCCAA concurs with this sentiment. IPCCAA noted that The FIRM Group then suggests that utilizing actual load rather than forecast load along with an hourly allocation of the deferral account balances (including an hourly allocation of UOV refunds) would accomplish this. IPCCAA does not agree with this as the argument is flawed. IPCCAA noted that the mechanism by which loads “retain the benefits of their actions” has two components—reduced allocation of the Pool purchase component of the deferral account in hours when load was curtailed (the part acknowledged by the FIRM Group) and also an entitlement component whereby the load that curtailed should be able to capture the entitlement value associated with their curtailed load (the part ignored by the FIRM Group).
IPCCAA stated that the FIRM Group is positing that acknowledging lower allocations of the Pool Purchase deferral component for load curtailed in response to high Pool Price is appropriate but they do (sic not) provide any argument as to why load curtailed in response to high Pool Prices should receive no recognition of the higher UOV refunds received in the hours of curtailment.
Absent any price responsiveness, IPCCAA noted that these loads would have received a share of the UOV refunds. IPCCAA stated that providing a share of the UOV refund to the curtailed load would leave other loads no worse off, and potentially better off due to the downward pressure on Pool Price resulting from lower load.
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As quoted in the IPCCAA Argument (at Page 209), IPCCAA stated that the Board described how the UOV allocation should not diminish Pool Price signals.
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. (U99035, Page 23, emphasis added)
For a load that curtails in an hour with a high Pool Price, IPCCAA stated that an hourly Pool purchase deferral allocation does not allocate Pool purchase amounts to curtailed load and this is appropriate. But an hourly UOV refund allocation improperly excludes curtailed load from the benefits of the high UOV refund in such an hour. An hourly mechanism for allocating UOV refunds diminishes the strength of the market-determined price (Pool Price) by requiring the load to consider not just avoided Pool purchases, but also foregone UOV refunds in their curtailment decision. Exhibit 911 provided an example of how the DAT provided a portion of the legislated hedge related to the hour of curtailment to a curtailed load. The deferral account allocation should accomplish the same in respect of Option G. An hourly allocation of UOV refunds, as suggested by the FIRM Group, does not accomplish this.
IPCCAA stated that the FIRM group provide numerous statements of a similar ilk: don’t mask Pool Price signals, allocate less to loads that had lower use in on-peak periods, don’t claw back benefits from curtailed load etc. IPCCAA agrees with these sentiments. But each of the FIRM group statements is accompanied by a misleading suggestion that these goals would be achieved through the use of a top-down allocation with an hourly allocation of UOV. IPCCAA stated that this is simply not true. IPCCAA stated that its Argument (page 28) clearly demonstrates that the hourly UOV allocation has exactly the opposite effect suggested by the FIRM Group: an hourly UOV allocation masks Pool Price signals, allocates less to loads that had higher use in on-peak periods and claws back benefits from curtailed load.
IPCCAA stated that examples of the FIRM Group’s misleading statements are provided and addressed separately, below. (Note that in each case where the FIRM Group refers to the top- down approach, they mean a top-down approach with an hourly allocation of UOV refunds. IPCCAA has indicated this by adding the clarifying note in a number of the citations.)
The FIRM customers submit that the issue of masking pool price signals is really an issue of ensuring that customers, who consumed less energy during periods of high hourly Pool prices, should benefit from that consumption pattern. The exercise of liquidating the 2000 Distribution Pool Price Deferral Account should not claw back benefits from those customers who curtailed loads during periods of high hourly Pool price. (FIRM Group Argument, Page 65, emphasis added)
IPCCAA stated that the FIRM proposal would claw back benefits from customers who curtailed load. As described earlier, there are two components to the benefits of curtailed load: reduced Pool purchases and retaining the entitlements in respect of the curtailed load. The FIRM proposal
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for hourly allocation of UOV refunds would prevent curtailed loads from receiving any credit for entitlements in respect of curtailed load.
The Firm customers submit that the top-down approach [with an hourly allocation of UOV refunds] is more consistent with the price signals that customers were exposed to during 2000. The customers had no ability to determine price signals based on the bottom-up approach during 2000 and therefore, had no ability to react to price signals based on a bottom-up approach. Therefore, the top-down approach better achieves the goal of ensuring that Pool price signals during 2000 are not masked.
As demonstrated in Exhibit 1008 and 1013, the top-down approach (with an hourly allocation of UOV refunds) results in a lower cost allocation to Option G customers who curtailed load during periods of high hourly Pool price. (FIRM Group Argument, Pages 65 and 66, emphasis added)
Page 28 of the IPCCAA Argument shows that a top-down approach with an hourly allocation of UOV refunds would allocate $10.6/MWh to Option G while a top-down allocation with a monthly UOV allocation would allocate $3.2/MWh to Option G.
IPCCAA submits that exhibits 1008 and 1013 do not demonstrate that the top-down approach (with hourly allocation of UOV refunds) results in lower cost allocation to Option G customers. The FIRM reference to a “lower cost allocation ” refers to an improper comparison of lower percentages of total amounts allocated to Option G. The cases being compared are not the least bit similar. Exhibit 1008 compares UNCA’s allocation to Option G as $10.6 million of a total of $319.1 million or 3.34%. The “lower” top-down allocation to Option G is $10.4 million out of $381.2 million, or 2.73%. The UNCA values used are after recognition of the $92 million collected through deferral riders in 2000 (none of which were collected from Option G). The FIRM Group numbers do not recognize the deferral rider amounts. The two are not comparable in any way, shape or form. Therefore, IPCCAA stated that the FIRM Group’s conclusion that “the top-down approach (with hourly allocation of UOV refunds) results in lower cost allocation to Option G customers” is entirely without support.
To compare the treatment of Option G under various allocation methods, IPCCAA stated that its Exhibit 914 is more meaningful for a number of reasons. It compares allocations for Pool purchase and UOV components only, with no effect of differing methodologies for GENCO amounts. It includes appropriate adjustments to Option G revenue to rectify the UNCA approach requiring Option G loads to pay themselves hedges in respect of curtailed load.
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Table 18: Comparison of Rate Class Allocations (IPCCAA) Comparison of Rate Class Allocations Pool Price and UOV Components Only $ 000 Top-Down Top-Down Bottom-Up Hourly PP and Hourly PP and UNCA with Hourly UOV Monthly UOV Rate Class Description Rate Code Adjustments Allocation Allocation REA Farm 24XX–25XX 10,181 8,800 10,221 UNCA Irrigation 26XX–27XX 1,605 3,476 3,028 REA Irrigation 28XX–29XX 10 26 23 Exterior Lighting 3XXX (243) 1,130 (529) Small General Service 41XX–43XX 31,881 21,511 32,657 Pumping 44XX–46XX 12,865 14,998 12,761 General Service 61XX–62XX 109,061 100,808 110,487 Large General Time-of- 63XX 50,689 51,928 48,962 Use Direct Connected Service 65XX 143,164 165,162 141,117 Direct Access Tariff 68XX 0 0 0 Option G Option G 2,570* 12,249 3,706 Wholesale Service 81XX 3,172 2,291 3,194 (Closed) Total UNCA — $433,763 $433,762 $433,762 Source: Exhibit 914, Tab 1 Comparison. * $3.4 million with H-factor adjustment per IPCCAA Argument, Page 41
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IPCCAA noted that it can be seen that utilizing a top-down approach with an hourly UOV allocation (as suggested by the FIRM Group) would greatly increase the deferral account allocation to the Option G loads.
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Table 19: Comparison of Rate Class Allocations ($/MWh) (IPCCAA) Comparison of Rate Class Allocations Pool Price and UOV Components Only $/MWh Rate Class Description Rate Code Bottom-Up with Top-Down Top-Down Adjustments Hourly PP and Hourly PP and Monthly UOV Hourly UOV Allocation Allocation Residential 11XX–12XX $27.12 $26.93 $19.59 UNCA Farm 21XX–23XX 22.12 21.68 18.66 REA Farm 24XX–25XX 21.30 21.39 18.41 UNCA Irrigation 26XX–27XX 7.11 13.41 15.39 REA Irrigation 28XX–29XX 6.27 13.98 16.13 Exterior Lighting 3XXX (3.49) (7.59) 16.21 Small General Service 41XX–43XX 30.08 30.81 20.30 Pumping 44XX–46XX 5.78 15.65 18.40 General Service 61XX–62XX 20.63 20.90 19.07 Large General Time-of- 63XX 18.17 17.55 18.61 Use Direct Connected Service 65XX 15.90 15.67 18.34 Direct Access Tariff 68XX 0.00 0.00 0.00 Option G Option G 2.22 3.20 10.56 Wholesale Service 81XX 27.48 27.67 19.85 (Closed) Total UNCA — $17.91 $17.91 $17.91 Source: Exhibit 914 divided by Schedule 8-G Energy. * $2.93/MWh per IPCCAA Argument, Page 41
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In fact, IPCCAA stated that the FIRM group’s recommendation would increase the unit deferral allocation to Option G from UNCA’s filed $8.96/MWh (FIRM.UNCA DISCO-13, Exhibit 1004) (an amount that excludes IPCCAA’s proposed Option G revenue adjustments) to $10.56/MWh. This would have Option G loads paying a higher unit deferral amount than non-price responsive loads. (The $8.96/MWh was UNCA’s average proposed deferral allocation to 6300 and 6500 load over the 8 months the Option G was in existence). IPCCAA submits that this result does not ensure that loads curtailing in response to high Pool Prices retain the benefits of that curtailment.
IPCCAA stated that additional problems with Exhibit 1008 include the comparison of the Option G allocation to UNCA’s schedules. IPCCAA has thoroughly described the errors in UNCA’s calculation of revenue ascribed to Option G loads in Argument. (IPCCAA Argument, Pages 43- 46 “Treatment of Option G in UNCA’s Bottom-up Allocation”) Any FIRM Group comparison to UNCA’s Option G allocation is flawed as it compares against unreasonably high allocations.
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IPCCAA stated that Mr. Reimer’s calculations underlying the FIRM Group values in Exhibit 1008 exaggerated the load for transmission-connected customers (and most Option G loads are direct-connect loads) and therefore overstated the allocations to these loads:
15 Q All right. Now, apropos of that, I would assume that 16 you would agree that one effect of your allocation 17 method or the application of the energy 18 reconciliation factor, to be precise, was to increase 19 the load of the transmission direct-connect customers 20 by a factor that includes distribution losses, yes? 21 A MR. REIMER: Yes. I think that is fair. 22 Q Right. But it is true, is it not, Mr. Reimer, 23 that -- well, let me back up a step. 24 And it follows, of course, that 25 the effect of that approach is that transmission 26 direct-connect loads receive a larger allocation of 6062 01 the deferral accounts than they would otherwise, yes? 02 A MR. REIMER: Yes. That is correct. (26T6061-6062)
IPCCAA stated that the FIRM Group provides another goal with which IPCCAA agrees, that is, ensuring that loads that consume less in on-peak times are allocated less of the deferral account, but, again, the mechanism proposed by the FIRM Group would achieve exactly the opposite result.
The FIRM customers recommend that the Board direct the distribution functions to use the top-down approach (with an hourly allocation of UOV refunds) to ensure that customers who curtailed load, or normally consume less energy during periods of high Pool price, receive the full benefit of their load profile. (FIRM Argument, Page 66, emphasis and text in brackets added)
IPCCAA stated that the FIRM Group statement suggests that they would like to see lower deferral account allocations to customers who “normally consume less energy during periods of high Pool price”. Looking at the weighted average cost of Pool purchases (IPCCAA Argument, Page 25), it can be easily seen that Small General Service and Residential consume more energy during periods of high Pool Price (their weighted average cost is significantly higher than the average Pool Price of $133/MWh).
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Table 20: Average Power Pool Purchase Cost $/MWh (IPCCAA) Average Power Pool Purchase Cost$/MWh Difference from Avg. PP Rate Class Description Rate Code Weighted Average $/MWh Residential 11XX–12XX 145.51 +12.29 UNCA Farm 21XX–23XX 137.78 +4.56 REA Farm 24XX–25XX 135.92 +2.70 UNCA Irrigation 26XX–27XX 115.13 N/A REA Irrigation 28XX–29XX 120.71 N/A Exterior Lighting 3XXX 107.52 -18.09 Small General Service 41XX–43XX 151.14 +17.92 Pumping 44XX–46XX 133.36 +0.14 General Service 61XX–62XX 139.88 +6.66 Large General Time-of-Use 63XX 135.39 +2.17 Direct Connected Service 65XX 133.56 +0.34 Option G (Jan-Aug) Option G 85.87 N/A Wholesale Service (Closed) 81XX 146.82 +13.60 Source: Exhibit 913, Tab 8-D Purchases divided by 8-G Energy.
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IPCCAA stated that the higher average Power Pool purchase cost suggests that the FIRM Group would expect larger deferral account allocations to Small General Service and Residential loads and lower deferrals to groups that consume relatively more in lower Pool Price periods, such as Large General Service and Direct-Connected. But this is not the result that would be achieved with the FIRM Group’s proposed top-down approach with hourly UOV allocations (compared to a bottom-up or top-down allocation with monthly UOV refunds). A top-down approach with hourly UOV allocations would calculate $19.6/MWh for residential load whereas with a monthly UOV allocation the amount would be $26.9/MWh. (values from the table “Comparison of Rate Class Allocations” set out earlier in this reply)
IPCCAA stated that Mr. Reimer even acknowledges this in Exhibit 1013 wherein he states:
While it is apparent that when UOV credits are dispensed on the basis of total monthly energy consumption, instead of hourly, customer groups that consume more energy coincident to high Pool prices receive lower amounts of UOV credits and their portion of the 2000 Pool Price Deferral account increases.
IPCCAA submits that this is another example of the FIRM Group attempting to mislead the Board.
IPCCAA stated that the FIRM Group repeats the same misleading phrases over and over:
The FIRM customers submit that the suitable allocation methodology should reward those consumers that helped alleviate the 2000 Distribution Pool Price
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Deferral Account by reducing energy consumption, or by having a load profile whereby less energy is consumed during periods of high Pool price.
The top-down approach [with an hourly allocation of UOV refunds] provides a larger benefit to customers who curtailed load, or did not consume as much energy during periods of high hourly Pool prices. (FIRM Argument, Page 69, emphasis added)
The FIRM customers submit that the top-down approach results in a reduced allocation of deferral account costs to those rate classes that reduced consumption during periods of high Pool Price. The top-down approach [with an hourly allocation of UOV refunds] better recognizes the contribution that Option G customers made to reduce the overall costs of the deferral account. (FIRM Argument, Page 69, emphasis added)
IPCCAA Reply to FIRM Group “Reasons” Why Its Hourly Top-Down Approach is “Superior”. As outlined by IPCCAA in Exhibit 913 and discussed in IPCCAA’s Argument at Pages 38-41) with appropriate adjustments to Option G revenue the bottom-up and top-down methodologies give very similar results. The most significant question is not whether the top-down or bottom-up allocation is utilized. IPCCAA stated that the real issue is the approach to allocation of UOV refunds.
The FIRM Group, in Argument, present 8 points, each of which is addressed below:
Precise IPCCAA stated that the FIRM Group states the top-down approach (with hourly allocation of UOV refunds) “simply applies the deferral formula determined in 2000-3” (FIRM Argument, Page 62).
IPCCAA stated that “Simply” is an appropriate term here as the FIRM Group has provided no basis to establish that the hourly UOV calculation they propose (but manage to never state) (a) provides for a fair allocation of entitlements, (b) provide loads that curtail an equitable share of entitlements in respect of curtailed load or (c) are not inconsistent with the treatment received by DAT loads and therefore discriminate against the DAT loads.
IPCCAA stated that the FIRM Group never states that it proposes an hourly UOV allocation, instead it refers to calculating the hourly deferral account amount (Pool Price and UOV components) and allocating the hourly amount by load. The two deferral amounts are separate— Pool Price-related amounts and UOV-related amounts. In the 1996 Phase II, Pool purchases were calculated on an hourly basis and UOV refunds (along with Reservation Payments) were allocated on an annual basis.
IPCCAA stated that the FIRM Group proposal is to allocate Pool purchase components of the deferral accounts hourly and UOV components of the deferral accounts hourly, whether they state it clearly or not.
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Accurate IPCCAA stated that the FIRM Group suggests that “forecast data along with load profiles are required to determine hourly consumption where interval-recording meter data is not available” (FIRM Argument, Page 63). Forecast data was not used—actual energy data was used and load profiling was undertaken to deem hourly amounts for non-interval metered data. If the FIRM Group had any problem with this, IPCCAA stated that they did not bring it up in this proceeding.
Both the top-down and bottom-up approaches use the same data as well the same data is utilized for hourly or monthly allocations whether the allocations are of Pool purchases, Pool Price deferral components, UOV refunds or UOV deferral components.
IPCCAA stated that the FIRM Group suggests that UNCA did not account for line losses properly.
The Firm customers recommend that the Board direct that UNC use distribution line losses by rate class to adjust consumption data back to the Transmission Administrator’s POD in the same manner that ATCO DISCO has proposed. (FIRM Argument, Page 63)
IPCCAA stated that to support this, the FIRM Group cites only its calculation of what it referred to as an “hourly reconciliation factor”. This factor reconciles hourly data at the customer meter provided by UNCA with total energy at the TA interface. UNCA provided two sets of hourly data by rate class: rate class load at the customer meter (UNCA-SPPA-2) and rate class load at the TA interface (IPCCAA.UtiliCorp-4). It is readily apparent from the differences in these two sets of data that UNCA incorporated losses by rate class. The loss factors by rate class used by UNCA are presented in Table 2 of IPPSA/SPPA.UNCA DISCO 2-2.
Simple IPCCAA stated that the FIRM Group states:
Most consumers would have had great difficulty (if they could do it at all), calculating rates with the bottom up approach during 2000. If the customers could not calculate rates, the customers would have had no means of formulating strategies to deal with the price signals during 2000. (FIRM Argument, Page 64)
IPCCAA stated that the FIRM Group appears to be suggesting that customers based their consumption decisions in 2000 on the embedded cost rates they were paying plus their assessment of the deferral account balances, assuming an hourly top-down allocation. Thus, the FIRM Group appears to be arguing that an approach other than a top-down approach with hourly UOV allocation would be “retroactive ratemaking” and be unfair.
IPCCAA stated that clearly, there is no evidence of this nor any basis for such an argument.
IPCCAA stated that the previous FIRM Group statement appears inconsistent compared to the following:
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The FIRM customers submit that the issue of masking Pool price signals is primarily an issue of rate design going forward – no one is able to go back to 2000 and change their hourly consumption based on price signals determined at the conclusion of this exercise. (FIRM Argument, Page 65)
IPCCAA stated that the FIRM Group then argued that the top-down approach is simpler to understand. IPCCAA submits that any explanation of the events of 2000, leading to the accumulation of hundreds of millions of dollars in deferral account balances, is well past any threshold of simple. Furthermore, IPCCAA stated that a monthly allocation of UOV components is as simple as an hourly allocation.
Fair As described above, the top down approach is precise, accurate, and simple. In result, consumers will more likely consider recovery of the 2000 Distribution Pool Price Deferral Account, as fair. (FIRM Argument, Page 64)
IPCCAA stated that the logic presented is certainly more efficient than addressing issues such as whether the hourly UOV allocation is fair, whether it provides appropriate entitlement allocation to curtailed load and other issues addressed in the IPCCAA Argument.
Masking Pool Price Signals IPCCAA stated that the FIRM Group is proposing the top-down approach and begins this section discussing a cost of service step and a rate design step, both of which are unique to the bottom- up approach. IPCCAA stated that it states “the issue of masking Pool price signals is irrelevant in the cost of service step” (Page 65). IPCCAA submits that this assertion is quite unbelievable, as the cost of service step involves the allocation of UOV refunds.
IPCCAA noted that the FIRM Group goes on to state: Therefore, the top-down approach (with an hourly UOV allocation) better achieves the goal of ensuring that Pool price signals during 2000 are not masked. (FIRM Argument, Page 65, emphasis and text in brackets added)
IPCCAA stated that clearly the FIRM Group’s conclusion is incorrect. As demonstrated in IPCCAA’s Argument (Pages 25 and 29), a monthly UOV allocation preserves the rate class differentials in Pool purchase costs, whereas an hourly UOV allocation virtually eliminated the differentials.
IPCCAA noted that the differential between Pool purchase cost between Small General Service and Direct-Connected is roughly $18/MWh (IPCCAA Argument, Page 25). With a monthly UOV allocation, the differential in the deferral account allocations is $15/MWh ($30.8-$15.7, IPCCAA Argument p. 28) and, with an hourly UOV allocation, the differential is $2/MWh ($20.3-$18.3, IPCCAA Argument, Page 28).
IPCCAA stated that clearly the top-down approach with an hourly allocation of UOV refunds masks virtually all Pool Price signals.
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Incremental Costing The cost of service exercise should be concerned only about accurately allocating costs to each rate class and the cost of service exercise should not be confused with issues such as averaging (FIRM Argument, Page 66, emphasis added)
IPCCAA stated that the FIRM Group does not describe what it considers to be “averaging”. IPCCAA stated that perhaps this is its term for allocation of UOV refunds. Allocation of UOV refunds is the main issue with respect to allocation of the deferral accounts. The FIRM Group has offered no evidence to demonstrate the fairness of allocating UOV refunds on an hourly basis. As indicated in IPCCAA’s version of the “hot dog” analogy in this Reply, an hourly UOV allocation is equivalent to providing predominantly on-peak loads with more on-peak entitlements than flat high load factor loads.
Embedded Cost Rate Design IPCCAA stated that the FIRM Group appears to suggest that the bottom-up approach would need to recognize 10% price caps that were contemplated in Decision U99035. Clearly, IPCCAA stated that we are all beyond the façade of 10% price caps influencing application of the bottom- up approach. A top-down approach will apply deferral riders that would far exceed a 10% price cap for most, if not all, rate classes (if collected in one year).
IPCCAA stated that he FIRM Group include reference to AE DISCO’s comments but AE DISCO’s situation is different in that if it were to apply the bottom-up approach, it claims that it would have to determine which component of the 100% R/C shortfall was attributable to the generation component. The FIRM Group appears to claim difficulty with determining the revenue component, not the cost allocation. Under the heading “Allocation Methodology “Top- Down vs. Bottom-Up”” IPCCAA describes why AE DISCO’s comments on the bottom-up methodology are groundless. The same arguments apply to the FIRM Group’s comments on the supposed impacts of rate caps on the bottom-up allocation. IPCCAA stated that the FIRM Group suggests that the “top-down approach (with an hourly allocation of UOV refunds) better reflects price signals that customers were exposed to in 2000 – that is embedded cost based rates in effect during 2000, plus the deferral account formula” (FIRM Argument, Page 68, emphasis and text in brackets added).
IPCCAA stated that the top-down approach does not reflect the embedded cost rates that were in effect in 2000. In fact the top-down approach totally ignores the embedded cost rates in place in 2000. As discussed in Exhibit 913, Page 3, one reason the bottom-up allocation for irrigation is different from the top-down allocation is that the bottom-up recognizes that irrigation had the highest energy charge of any of the rates. The bottom-up, therefore, calculates higher revenues (and, therefore, lower deferral amounts) than the top-down approach that ignores the varying level of tariffs paid by different rate classes in 2000.
IPCCAA stated that the FIRM Group’s argument that the top-down approach (with hourly allocation of UOV refunds) better reflects the price signals that were in the embedded rates is flawed and should be disregarded by the Board.
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Impact on Customers IPCCAA stated that in its argument on this issue, FIRM Group repeats, yet again, this statement:
The FIRM customers submit that the top-down approach (with hourly UOV allocation) results in a reduced allocation of deferral account costs to those rate classes that reduced consumption during periods of high Pool Price. The top- down approach better recognizes the contribution that Option G customers made to reduce the overall costs of the deferral account. (FIRM Argument, Page 69, emphasis and text in brackets added)
IPCCAA stated that as it has demonstrated, the hourly UOV allocation proposed by the FIRM Group significantly increases the deferral account allocation to parties that curtailed load in response to high hourly Pool Prices.
1.4 Views of FIRM FIRM stated that two general approaches have been developed to allocate the 2000 Pool Price Deferral Account by rate class. AE Disco’s proposed approach is to apply the 2000 Pool Price Deferral Account formula on an hourly basis to determine the deficit (or surplus) incurred in each hour, and to recover that deficit from all energy consumers in that hour on the basis of energy consumption. This approach has been referred to as the top-down approach. UNC has proposed an allocation method whereby rates are designed in the traditional manner of using forecast load and costs, but instead using actual hourly Pool price. The UNC approach has been referred to as the “bottom-up” approach.
FIRM stated that the traditional approach for determining rates is to perform a cost of service study by assigning and allocating costs as precisely and as accurately as possible to each rate class, and then to design rates based on approved rate design criteria. This process is traditionally done using forecast load and cost information.
FIRM stated that rates for 2000 were designed on the traditional approach with the knowledge that an adjustment would occur as the result of a 2000 Distribution Pool Price Deferral Account. New interim rates were effective on March 1, 2000 based on Decision 2000-12.
FIRM stated that the AEUB had concerns over the accuracy of a forecast of hourly Pool Price and in Decision 2000-3, implemented a Deferral Account. At Section 6.7, the following appears:
The Board considers that it clearly stated in the decision that pool price variance should be covered by deferral accounts and be to the account of customer and that volume variance is not included in deferral accounts and should be to the account of shareholders. The only question that arises is with respect to the cross over between these two variances, that is, the pool price variance on the difference between actual and forecast generation volumes. In other words, the Board agrees with TransAlta that the key issue is whether the Board intended that the utility be exposed to actual pool price for any difference between actual and forecast generation volumes. . . . The Board considers it was the intent that, due to the
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increased volatility of the pool price, that all pool price variances were covered by deferral accounts.
FIRM stated that another question arises with respect to the volume variance that resulted from customers’ reaction to the hourly Pool price. FIRM stated that Option G customers were subject to the hourly Pool price and generally reacted by reducing load (as previously mentioned, a trend can be established for Option G customers in IPPSA/SPPA.UNC 2 and 3(a and c) where load is lower during hours of high hourly Pool price).
FIRM stated that the customers that reduced load in response to pool price should retain the benefit of their actions (V26, P6118, L1-17). In order to ensure that these benefits are not clawed back, the actual hourly energy consumption must be used, along with the hourly formula for calculating the 2000 Distribution Pool Price Deferral Account. Therefore, the practical approach is to use the actual hourly load for 2000 for those customers that have interval recording meter data, and to use forecast based load profiles for those customers that did not have interval recording meter data.
FIRM stated that both the top-down and bottom-up approach could be based on actual load data for customers with interval recording meter data and forecast load profiles for other customers.
FIRM stated that the top-down approach is superior to the bottom-up approach for numerous reasons. This approach is:
• precise, • accurate, • simple, • fair, • does not mask price signals, • consistent with incremental costing, • consistent with embedded cost rate design, • and its impact on customers ensures the benefits of curtailment are not clawed back.
Precise FIRM stated that the top-down approach is precise because it simply applies the deferral formula determined in Decision 2000-3. The formula for the Disco Pool price deferral account is as follows:
Pool price deferral = (Actual pool price – Forecast pool price) x (Actual energy purchases) - (Actual DISCO entitlement – Forecast DISCO entitlement)
FIRM stated that the basic units within the formula are based on hours. The Power Pool of Alberta determines the hourly Pool price. While the hourly Pool price can be averaged over a period of time, arithmetic averages will be different from weighted average prices, and weighted average prices over a period will be a function of the load profile. Further, rate classes with different profiles will have different weighted average pool prices over the same period. Energy purchases are metered hourly and entitlements are calculated from the hourly Pool price.
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FIRM stated that movement from an hourly calculation will result in reduced precision and the requirement to move to average, or weighted average hourly Pool prices. FIRM stated that the top-down approach uses the deferral account formula as a springboard for further cost allocation while the bottom-up approach uses the deferral account formula only to calculate the quantum of the deferral account.
The FIRM customers recommend that the Board direct calculations be done on an hourly basis for maximum precision.
Accurate FIRM noted that the deferral amount can be precisely calculated by hour, and along with consumption data by hour, the deferral amount can be accurately allocated to each rate class. Actual hourly consumption should be used where interval-recording meters provide the data. Forecast data along with load profiles are required to determine hourly consumption where interval-recording meter data is not available. Since customer meter data does not equal the meter data at the Transmission Administrators POD, reconciliation between the two is required.
FIRM stated that when the hourly deficit (or surplus) is applied to all energy consumption in the hour, the deficit can be accurately allocated to all consumers in that hour based on their energy consumption in that hour. Reconciling all customers’ energy consumption back to the Transmission Administrator’s POD will ensure additional accuracy. This can be accomplished by applying the line loss factors by rate class to the customers’ meter data as proposed by ATCO Disco. (Exhibit 407-1, Section 2)
FIRM noted that the customer meter data will not be the same as the Transmission Administrators POD meter data. Factors that lead to these differences include line losses, meter error and Unaccounted for Energy (UFE) (V26, P6060-6061). The average hourly reconciliation factor for UNC was approximately 5% with extreme hours as high as 23% and as low as –4% (V26, P6059-6060). In order to maximize the accuracy, those factors that can be calculated by rate class should be identified and used to minimize the reconciliation required between the customer meter data and the meter data at the Transmission Administrators POD.
The Firm customers recommend that the Board direct that UNC use distribution line losses by rate class to adjust consumption data back to the Transmission Administrator’s POD in the same manner that ATCO DISCO has proposed.
The FIRM customers submit that the top-down approach is more accurate than the bottom-up approach because the deficit is allocated to the energy consumption by hour instead of averaging over some longer period.
Simple FIRM stated that the top-down approach is simple and is easy to understand for customers. Customers were exposed to two primary rate signals during 2000, the rates set out in Decision 2000-12 and the deferral accounts set out in Decision 2000-3. Both factors were public knowledge and customers could formulate strategies to deal with these factors. The hourly Pool price was the primary factor in the creation of the deferral account and was one of the two
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primary price signals that customers were exposed to. FIRM stated that the top-down approach is consistent with customers’ exposure to price signals in 2000.
FIRM stated that most consumers would have had great difficulty (if they could do it at all), calculating rates with the bottom up approach during 2000. If the customers could not calculate rates, the customers would have had no means of formulating strategies to deal with the price signals during 2000.
FIRM stated that since the top-down approach is easier to understand, it is more likely to gain customer acceptance. The FIRM customers submit that the top-down approach is simpler to understand than the bottom-up approach and therefore, the Board should direct all distribution functions to use the top-down approach.
Fair FIRM stated that the top down approach to allocating the 2000 Distribution Pool Price Deferral Account is a fair method. As described above, the top down approach is precise, accurate, and simple. In result, consumers will more likely consider recovery of the 2000 Distribution Pool Price Deferral Account, as fair.
Masking of Pool Price Signals There was discussion about whether the allocation method would mask the hourly Pool Price signal to end use consumers. IPCCAA in its opening statement (V24;P5358) states, “that a main consideration should be to not mask Pool price signal”.
The FIRM customers submit that there are two steps in this process, the first step being that of cost of service, or allocating costs by rate class, and the second step is the recovery of costs or rate design.
The FIRM customers submit that the issue of masking Pool price signals is irrelevant in the cost of service step. The purpose of the cost of service step is to obtain the most precise and accurate allocation of costs by rate class.
The FIRM customers submit that the issue of masking Pool price signals is primarily an issue of rate design going forward – no one is able to go back to 2000 and change their hourly consumption based on price signals determined at the conclusion of this exercise.
The FIRM customers submit that the issue of masking pool price signals is really an issue of ensuring that customers, who consumed less energy during periods of high hourly Pool prices, should benefit from that consumption pattern. The exercise of liquidating the 2000 Distribution Pool Price Deferral Account should not claw back benefits from those customers who curtailed loads during periods of high hourly Pool price.
The FIRM customers submit that the top-down approach is more consistent with the price signals that customers were exposed to during 2000. The customers had no ability to determine price signals based on the bottom-up approach during 2000 and therefore, had no ability to react to
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As demonstrated in Exhibit 1008 and 1013, FIRM stated that the top-down approach results in a lower cost allocation to Option G customers who curtailed load during periods of high hourly Pool price.
The FIRM customers recommend that the Board direct the distribution functions to use the top- down approach to ensure that customers who curtailed load, or normally consume less energy during periods of high Pool price, receive the full benefit of their load profile.
Incremental Costing FIRM stated that the top-down approach has been compared to an incremental cost of service approach that disregards rate design (V26, P6137) while the bottom-up approach is more of a pricing approach.
FIRM stated that the current exercise can be considered in two parts. The first part is the cost of service that includes the allocation of costs to each rate class, and the second part is the rate design that determines the level and structure of the rate to recover the costs.
FIRM stated that the cost of service exercise should be concerned only about accurately allocating costs to each rate class and the cost of service exercise should not be confused with issues such as averaging. The rate design exercise must consider the amount of averaging, inter- rate class subsidies, rate shock, energy charge versus demand charge, and other issues that result in the final tariff.
Therefore, the FIRM customers submit that the top-down approach is a better approach for allocating the costs of the 2000 Distribution Pool Price Deferral Account to each rate class. The FIRM customers submit that the issues of rate design are not in dispute, there should be no inter- class subsidies, and that recovery should occur on an energy consumption basis.
FIRM stated that the top-down approach better emulates the actual situation that occurred during 2000 whereby rates were designed based on embedded costs (Decision 2000-12) and market fluctuations coupled with unhedged purchases resulted in the deferral account in a separate process (Decision 2000-3). The bottom-up approach averages purchases made under legislated hedges with purchases at the margin (even though the price difference may be large).
The FIRM customers submit that the top-down approach better reflects the transition of the old world generation cost allocation methods during the last year of a five-year transition to deregulation in 2001.
Embedded Cost Rate Design FIRM stated that the rates set out in Decision 2000-12 were those rates based on traditional embedded cost/rate design and vetted through a regulatory process. The bottom-up approach is consistent with the regulatory process used to set rates on a prospective basis.
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FIRM stated that the bottom-up approach recalculates rates for 2000 on the basis of substituting actual hourly Pool price for forecast hourly Pool price, and to use actual load instead of forecast load (particularly for those customer groups that have interval recording meter data and who had exposure to the hourly Pool price).
The FIRM customers submit that the bottom-up approach of simply substituting actual prices and loads for forecast prices and loads should not be carried out with out a review of the impact of such exercise. This exercise is analogous to having gone through the entire cost of service and rate design exercise with appropriate forecast information and designing final rates on a prospective basis for 2000.
FIRM noted that the average actual hourly Pool price for 2000 was $133.22/MWh while the average forecast hourly Pool price for 2000 was $28.52/MWh (BR.UNCA-Disco 1 (a and b), Columns C and D). With the actual price being several times greater than the forecast price, the results of a bottom-up approach may have violated Board directions from previous decisions. For example, in Decision U99035, Page 52, the Board directed TransAlta to limit the overall increase in revenue to less than 10% for every rate class. Therefore, had the actual hourly Pool price for 2000 been known at the time that rates were designed for 2000, Board directions would have impacted the final rates, and the results would have been different than a bottom up approach applied in 2001 without the constraints of the Board directives contained in Decision U99035.
FIRM noted that ATCO DISCO pointed out that for their rates in effect for most of 2000, three rates were limited by the 10% increase cap, and had the actual 2000 hourly Pool price been known, these rates would not have changed because they were already limited by 10% increase cap (V23, P 5078-5079).
With the knowledge and use of actual hourly Pool Price in the design of rates for 2000, FIRM stated that the Time-of-Use rates would have changed. With the actual price being several times higher than the forecast price, generation energy charges would have been higher and Time-of- Use differentials would also have been modified. The change in rates may have impacted customer decisions to consume energy (V23, P 5079-5080 and V26, P 6127).
The FIRM customers submit that the bottom-up approach of rate design based on Board directives for the year 2000 may yield different results than using the bottom-up approach for the purpose of allocating the 2000 Distribution Pool Price Deferral Account.
The FIRM customers submit that the top-down approach of allocating the 2000 Distribution Pool Price Deferral Account does not suffer the stigma of retroactive rate design.
The FIRM customers submit that the top-down approach better reflects the price signals that customers were exposed to in 2000 – that is the embedded cost based rates in effect during 2000, plus the deferral account formula.
Impact on Customers The two allocation methodologies result in varying allocations to each rate class as shown in Exhibit 1008 and Exhibit 379.
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The FIRM customers submit that the suitable allocation methodology should reward those consumers that helped alleviate the 2000 Distribution Pool Price Deferral Account by reducing energy consumption, or by having a load profile whereby less energy is consumed during periods of high Pool price.
FIRM stated that the top-down approach provides a larger benefit to customers who curtailed load, or did not consume as much energy during periods of high hourly Pool prices.
Exhibit 379, comparison of the top-down and bottom-up allocation method indicates that the Option G customers would experience an increase in allocated costs of 4.3% when moving from the bottom-up to the top-down approach. This calculation included an adjustment for Option G to maintain revenue neutrality. The FIRM customers submit that the adjustment for revenue neutrality should be excluded and that Option G customers will experience a reduction in allocated costs when moving from a bottom-up to a top-down approach.
While revenue neutrality is the goal in the calculation of the GAC, (the GAC was calculated to provide revenue neutrality between customers on Option G and comparable rates (790 or 6300- 6400) (Exhibit 378), revenue neutrality is not required if a customer curtailed load during periods of high hourly Pool prices (V26, P6117)
The FIRM customers submit that the top-down approach results in a reduced allocation of deferral account costs to those rate classes that reduced consumption during periods of high Pool Price. The top-down approach better recognizes the contribution that Option G customers made to reduce the overall costs of the deferral account.
The FIRM customers have just received IPCCAA undertakings Exhibits 913 and 914 and have not been able to examine the information in these undertakings. The FIRM customers reserve the right to provide further Argument with respect to issues covered in these undertakings.
Summary and Recommendations: a) The FIRM customers submit that the top down approach better reflects cost causation and that the Board direct the distribution functions to use the top down approach to allocate the cost of the 2000 Distribution Pool Price Deferral Account to each rate class. b) The FIRM customers submit that UNC be directed to use ATCO Disco’s method of allocating line losses to each rate class to improve the accuracy of the cost allocation.
The FIRM customers submit that Option G customers be included in the allocation of costs since the calculation of the GAC was designed such that Option G was revenue neutral to Rate 6300- 6400 (Exhibit 378). The GAC calculation was intended to make Option G revenue neutral to Rate 6300-6400 prior to any load curtailment by Option G customers (V26, P6114). To the extent that Option G customers curtailed load, they received a lower bill under Option G.
FIRM stated that IPCCAA and UNCA claim that Decision U99035 supports separate allocations of pool purchases and UOV in their Argument. The FIRM Customers do not agree.
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FIRM stated that the rational for separate allocation of UOV and pool purchases during 1998 was based on several factors that had changed by 2000.
First of all, FIRM stated that a larger percentage of the utilities total energy purchases were hedged during 1998 than during 2000. The legislated hedges had the impact of masking market price signals and in 1998, when a larger portion of energy purchases were hedged, Pool price signals had very little effect on consumption behaviour.
Secondly, for 1998, FIRM stated that the UOV credits were uncoupled from the hourly pool purchases and averaged over a longer period so that the UOV would not offset the hourly Pool price and customers could be exposed to hourly Pool price.
Further, FIRM stated that a customer who shifted load (rather than develop a long term reduction in consumption) did not have to give up UOV credits because the customer was able to obtain the UOV credits during other hours when the customer made up lost production by increasing consumption.
The FIRM customers submit that IPCCAA and UNCA have interpreted Decision U99035 incorrectly. An hourly allocation is supported by U99035 at page 22:
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. 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.
In year 2000, FIRM noted that the Province was in the final year of the five-year transition from regulated generation to competitive generation. At this point, FIRM stated that the appropriate allocation of all generation related costs is on an hourly basis.
In 2000, FIRM noted that the situation had changed significantly due to a higher average hourly Pool price (average hourly Pool price of $33/MWh in 1988 and $133/MWh in 2000), and a larger portion of energy purchases was unhedged. This shift, had it been known, would have materially altered the cost of service and rate design between 1998 and 2000. Therefore, FIRM stated that it is not appropriate to simply recalculate rates for 2000 on the basis of using actual hourly Pool price instead of forecast hourly Pool price.
With the higher average hourly Pool price observed during 2000, FIRM stated that some loads may have been uneconomic and would have discontinued operations, rather than just shifting load from one hour to the next. Averaging UOV credits over a time period is effective for load shifting but does not work for discontinued load. Further, marginal purchases of energy were unhedged and on a marginal basis, there were no UOV credits to spread over other hours.
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FIRM stated that the change in situation between 1998 and 2000 can also be illustrated in relation to the Pool price deferral formula. In 1998, unhedged purchases were a small part of the overall actual energy purchases.
The Pool price deferral formula defined in Decision 2000-3 is as follows:
Pool price deferral = (Actual pool price – Forecast pool price) x (Actual energy purchases) - (Actual DISCO entitlement – Forecast DISCO entitlement)
In 2000, FIRM noted that the unhedged purchases became a larger part of the overall energy purchases, and the actual energy purchases can be considered in two components - hedged and unhedged energy purchases. The formula becomes:
Pool price deferral = (Actual pool price – Forecast pool price) x (hedged energy purchases) -(hedged Actual DISCO entitlement – hedged Forecast DISCO entitlement) + (Actual pool price – Forecast pool price) x (unhedged energy purchases) -(unhedged Actual DISCO entitlement – unhedged Forecast DISCO entitlement)
In the first portion of the Pool price deferral formula associated with hedged purchases, FIRM noted that the difference between actual and forecast pool price multiplied by hedged energy purchases is offset by the difference in UOV credits, and no amount accrues to the deferral account. In the second portion of the Pool price deferral formula, there are no entitlements associated with unhedged purchases. Therefore, the entire formula can be expressed as:
Pool price deferral = (Actual pool price – Forecast pool price) x (unhedged energy purchases)
With this formula, FIRM stated that it is clear that the deferral account accumulates hourly, but the question still remains how to allocate the sum to each rate class.
FIRM stated that the hourly nature inherent in the “top-down” approach implicitly assumes that load in each hour is responsible for the deficit or credit in that hour, and therefore avoids discrimination between rate classes.
FIRM stated that the mismatch in periods for allocation of pool purchases and UOV credits associated with the “bottom-up” approach will result in a shift of costs relative to how they were actually caused. UOV credits will be spread out by energy consumption over periods that may have no relation to the actual build up of the 2000 Distribution Pool Price Deferral deficit or credit.
The FIRM Customers submit that conditions during 2000 were significantly and materially different than in 1998, and it is inappropriate to apply Decision U99035 in allocation of the pool price deferral costs without deliberate and careful consideration of the changed circumstances. The FIRM Customers suggest that the “top-down” approach is the most precise, accurate and
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appropriate method of allocating the 2000 Distribution Pool Price Deferral Account to rate classes.
FIRM stated that the deferral account can be dealt with on its own merits and there is no purpose to reworking rates and cost allocations approved in Decision U99035. FIRM stated that the deferral account has accrued as a result of unhedged consumption and the associated hourly Pool price for each hour. Consequently, it is appropriate to allocate the deferral account on an hourly basis.
Appropriate Price Signals FIRM noted that IPCCAA argues that the monthly allocation of UOV preserves the hourly Pool price signal. (IPCCAA Argument - Pages 28 and 29).
The FIRM Customers disagree. FIRM stated that that the hourly allocation of the pool price deferral accounts is more consistent with the price signals that customers were exposed to during 2000. FIRM noted that the customers were exposed to the embedded rates, effective March 1 2000 that were approved on an interim basis in Decision 2000-12. Customers were also exposed to additional charges/credits as defined in the deferral account in Decision 2000-3. FIRM stated that it is clear customers reviewed this deferral account formula as an energy driven account based on the price each hour. From a practical perspective, customers were exposed to embedded cost rate schedules and the hourly Pool price. During all hours that the utility was purchasing energy without hedges, the hourly Pool price was the appropriate marginal price signal.
FIRM stated that the deferral account formula can be simply described as the variation in hourly Pool price, applied to the unhedged purchases of the utility. As such, FIRM stated that the hourly Pool price is the appropriate marginal price signal in all hours that the utility was purchasing unhedged energy.
In result, the FIRM Customers submit that the “top-down” approach is consistent with price signals that customers were exposed to during 2000 and should be used in the allocation of deferral account costs.
Annual – Monthly – Hourly Allocation of UOV FIRM noted that IPCCAA recommends that UOV be allocated on a monthly basis. IPCCAA argues that allocating UOV on an annual basis is inappropriate because it results in inequities to seasonal customers such as Option G who consumed load during 8 months of the year only. (IPCCAA argument, page 26) IPCCAA proposes that the allocation of UOV on a monthly basis will address the inequities arising from annual allocations to seasonal loads. IPCCAA also claims that averaging over a month is required to insure there is no interference with the hourly Pool price signal.
The FIRM Customers submit that an hourly allocation of UOV is better than a monthly allocation, and far better than an annual allocation to avoid interference with the hourly Pool price signal. Obviously, as UOV is averaged over a longer period of time, inequities result between customers that have differently hourly, monthly, seasonal and annual load profiles. The FIRM Customers submit that as the amount of unhedged purchases increases with respect to the
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1.5 Views of AIPA The UNCA allocation methodology has been characterized as the “bottom-up” approach and the AE DISCO and FIRM methodology has been characterized as the “top-down” approach in this proceeding.
The AIPA supports a bottom-up approach as the more appropriate methodology for allocating deferral account balances but has concerns with aspects of the UNCA proposed “bottom-up” approach including the monthly vs annual treatment of legislated hedges.
Legislated Hedges AIPA noted that a significant consideration in the allocation of deferral accounts is the treatment of legislated hedges. AIPA stated that the EUA ensured that the benefit of low cost generation was to be shared by customers. The legislated hedges allowed the cost of regulated generation to be passed through to customers. The fixed costs were recovered through reservation payments and the variable costs were recovered through the pool price revenues less the Obligation Value refunds. These refunds captured the difference between pool price and the UOP for the amount of hedged load.
AIPA stated that annual fixed costs and hourly pool prices complicate the pass through of total regulated generation costs to customers. AIPA stated that Decisions U99034 and U99035 established that legislated credits should be passed through to customers on the basis of fixed unit of consumption hedges that reflected annual obligation value refunds and annual reservation payments. From the perspective of a seasonal customer, AIPA stated that this approach ensured that low cost generation benefits were passed through as evidenced in the following at Transcript 4493:
05 Q Okay. Mr. Martin, also in Decision U99035 on 06 page 24, and I will just quote the passage. The 07 Board indicated that (quoted as read): 08 "Therefore, the Board considers the annual 09 forecast UOV refund should be treated as a 10 benefit that is spread equally across 11 forecast annual DISCO energy use. That will 12 ensure that the benefit related to existing 13 low-cost generation is equitably shared by 14 customers while also allowing customers to 15 be exposed to the full Pool price 16 variation." 17 Do you still support that 18 principle in the decision? 19 A MR. MARTIN: I think so.
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AIPA stated that when there is a departure from annual cost considerations, problems need to be addressed. For instance, reservation payments reflect the costs of all regulated generation and are passed through to all customers. However, AIPA noted that the availability of generation is lumpy in that units are taken out for scheduled maintenance. This maintenance is generally scheduled away from the peak winter season. In this way, seasonal summer customers do not have the same availability of generation yet pay for all this generation in the annual averaging of generation fixed costs. To the extent the amount of generation on maintenance shifts the supply merit curve, summer seasonal customers can be exposed to higher pool prices than would otherwise be the case with the full compliment of generation being available.
Rejection of Top-Down AIPA stated that the major problem with the top-down approach advocated by AE and FIRM in this proceeding is that this methodology ignores the principles for determining rates set in Decision U99034 for AE and U99035 for UNCA. AIPA stated that such principles included hourly allocations of pool price and annual allocation of UOVs and Reservation payments. AIPA stated that the AE and FIRM methodology ignores these principles and, we submit, cannot result in just and reasonable rates.
Problems with UNCA Bottom-Up From the evidence in this proceeding for both UNCA and AE allocations, AIPA stated that it is obvious that the major impacts for differences in approaches to deferral account allocations to rate classes occurs in the allocations to seasonal or part year customers. In fact, AIPA stated that such observations was the reason UNCA changed from the Board approved rate design methodology approved in the last TransAlta Phase II proceeding (U99035) as indicated in the following exchange:
08 Q Now, on page 4 of that rebuttal evidence, it is 09 suggested that Utilicorp departed from the approved 10 rate design methodology in U99035 where an annual 11 allocation was utilized to a revised methodology that 12 uses a monthly allocation. Do you see that? 13 A MS. KIRRMAIER: Yes. 14 Q One of the reasons for this change appears to be in 15 your observation that seasonal customers, such as 16 irrigation customers, would not receive an 17 appropriate allocation under the approved 18 methodology. Do I understand that correctly, 19 Ms. Kirrmaier? 20 A MR. MARTIN: That's correct. (Tr 4483)
And at Tr 4485/86/87, AIPA stated that UNCA specifically indicates that there has been a change in the allocation methodology with respect to legislated hedges:
22 Q Now, Mr. Martin, in terms of the legislated hedges, 23 by departing from the existing methodology, you have, 24 in effect, changed the Board approved fixed annual
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25 legislated hedge component, the so-called "H-factor" 26 per unit of consumption to a monthly variable 4485 01 H-charge which depends on monthly cost allocations 02 and monthly consumptions. Would that be a fair 03 statement? 04 A MR. MARTIN: We are proposing to do that. 4486 01 Q The intent, then, that you are suggesting is you have 02 now changed a fixed H-factor that was based on an 03 annual fixed H-factor to a so-called fixed H-factor 04 that is a monthly fixed H-factor; is that your 05 position, Mr. Martin? 06 A MR. MARTIN: That is our proposal in our 07 application, yes.
And at Tr 4487:
07 Q As we had discussed in Decision U99035, the Board had 08 decided that the legislated hedge component, the 09 so-called "H-factor" should be determined on the 10 basis of annual costs for reservation payments, the 11 annual credit for UOV payments, and the annual DISCO 12 consumption. Could you agree with that paraphrase? 13 A MR. MARTIN: Yes. That was in the Board 14 decision.
AIPA stated that a further complication with departing from the annual reservation payment allocations is the resulting non-equal treatment of equal monthly RP allocations as evidenced in the following at Tr 4489:
06 Q But if consumption in a seasonal summer month is 07 typically less than consumption in a winter month, 08 then won't the unit RP amount be greater for that 09 summer month? 10 A MR. MARTIN: If the reservation payments are 11 equal in each month and the total load of the utility 12 is lower in a month, then the unit reservation 13 payment would be higher in that month and proportionately lower in other months.
AIPA stated that there are problems with accepting the GENCO monthly amounts182 since they vary considerably month by month and are not in conformance with Decision U99099 as evidenced in the following:
182 UNCA Schedule 2.1 Rev 1, April 24, 2001, UNCA monthly share of GENCO deferral
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24 Q Now, if you keep that schedule in mind, I want to 25 read to you an excerpt from Decision U99099, 26 page 202. The Board at that page stated (quoted as 4514 01 read): 02 "The Board also recognizes that, as the FIRM 03 customers suggest, a further deferral 04 account is necessary to pass any cost 05 benefit arising to the DISCO from the GENCO 06 Pool price deferral account to TransAlta's 07 DISCO's customers. The amount in that 08 deferral account should be calculated 09 annually by multiplying the DISCO's 10 reservation payment share by the balance in 11 each of the AE, EPGI, and TransAlta 12 generating units Pool price deferral account 13 and summing the results." 14 Now, sir, has that annual GENCO 15 deferral estimate of the $47.254 million, has that 16 been applied as a credit to reservation payments in 17 your deferral calculations? 18 A MR. STROH: Yes, I believe it has. 19 Q And in those calculations, did you consider that 20 credit as an annual credit or a monthly credit in 21 your calculations? 22 A MR. STROH: Well, in terms of determining 23 the total deferral balance, it is a total annual 24 amount. 25 Q But in further determining your deferral account 26 allocations to rate classes, did you use a monthly 4515 01 allocation, or did you use an annual allocation 02 spread over equally? 03 A MR. MARTIN: It was a monthly allocation.
Costs and Revenues In the UNCA bottom-up methodology, AIPA stated that there is a discontinuity between costs and revenues particularly with a seasonal load such as irrigation service. On the cost side average DISCO power pool purchases are $135.41/MWh183 whereas the average purchase costs for irrigation service is $115.21/MWh184. The average legislated hedge credit (“H” Factor) is $90.79/MWh185 whereas the hedge credit for irrigation service is $76.03/MWh186.
183 Schedule 8-B Rev1, April 24, 2001: $3,325,459 / 24,558.5 GWh 184 Schedule 8-B Rev1, April 24, 2001: $26,015 / 225.8 GWh 185 Schedule 8-B Rev1, April 24, 2001: $2,198,827 / (24,558.5 – 338.9) GWh 186 Schedule 8-B Rev1, April 24, 2001: $17,167 / 225.8 GWh
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From these calculations, AIPA stated that it is apparent that irrigation costs are $20.21/MWh less than the DISCO average but in terms of the credit for legislated hedges the DISCO average is $14.76/MWh more the unit hedge allocated to irrigation service.
Now in terms of generation revenues, AIPA stated that there is an opposite effect with respect to average irrigation revenues and DISCO revenues. The average DISCO generation charge is $29.43/MWh187 and the UNCA irrigation charge is $34.12/MWh188. This is a difference of $4.69/MWh and to put this change into perspective it could impact 2000 irrigation revenues by $1,059,000189.
AIPA stated that these higher revenues for irrigation service arise from the setting of rates pursuant to Decision U99035 wherein generation charges were to be set on the basis of 1998 actual load and pool prices.190 The 1998 actual pool prices reflected an anomaly of higher pool prices in the summer consumption months. This higher level of pool price was embedded in irrigation rates. Furthermore with a constant hedge credit191 this causes a double hit for irrigation consumption in the current proceeding.
First of all, AIPA stated that irrigation generation revenues do not reflect the temporal pattern of 2000 pool prices. 1998 summer pool prices were higher than the annual average pool prices whereas 2000 summer pool prices are lower than the annual average.
Secondly, AIPA stated that the change in hedge credit works against the irrigation load.
For 1998, AIPA stated that with higher average summer pool prices, irrigation service only received a constant hedge credit, the same as all other rate classes. This caused the irrigation net generation charge to be higher relative to other rate classes. If the hedge credit had been calculated on the basis of monthly allocations (as per UNCA new methodology), AIPA stated that directionally a higher hedge credit for irrigation service would have resulted with consequent lower irrigation rates on a going forward basis.
For 2000, when summer average pool prices are lower than the annual average (115.21/MWh vs 135.41/MWh), AIPA stated that the UNCA proposed monthly cost allocation methodology causes a lower hedge credit for irrigation service than other rate classes (76.03/MWh vs 90.79/MWh). Effectively, AIPA stated that this causes an overstatement of irrigation service costs.
Therefore, the AIPA submits there is an obvious inconsistency in the proposed deferral account cost allocation process. Revenues reflect an annual allocation of hedges and costs reflect a monthly allocation of hedges. We submit it is patently unfair to penalize irrigation service with a
187 Schedule 8-C Rev 1, April 24, 2001: $722,973 / 24,558.5 GWh 188 Schedule 8-C Rev 1, April 24, 2001: $7,705 / 225.8 GWh 189 $4.59 / MWh * 225.8 GWh 190 Decision U99035, page 53 191 ibid, 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.
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high pool price estimate from 1998 and then exclude any benefit of a lower relative pool price in 2000 by changing the basic hedge allocation methodology.
AIPA stated that monthly GENCO amounts can cause a perverse allocation problem as evidenced in the following at Tr 4516:
24 A MR. STROH: Mr. Unryn, in the initial 25 application, we had a one annual number placeholder 26 from the GENCO amounts. Upon reviewing the GENCO 4517 01 deferral applications, we then had some monthly 02 information which we could use as well. 03 Q It was your choice, then, to not take the total 04 amount and allocate it equally to each to the months? 05 A MR. STROH: That's correct. 06 A MR. MARTIN: Yes, and we choose that to 07 attempt to replicate the treatment of reservation 08 payments and UOVs as a combined H-factor as in the 09 1996 Phase II decision. And it seemed appropriate to 10 deal with them both on a monthly basis. 11 So, that is why we handled 12 reservation payments on a monthly basis. 13 Q But if you look at your revised Schedule 8(f), the 14 monthly reservation amount for August is some 15 $51.9 million; the monthly amount for September is 16 $50.3 million, but the December amount is only 17 $6.9 million. Do you see that, sir? 18 A MR. MARTIN: Yes, I do. And that reflects 19 the reservation payments that would have accrued to 20 Utilicorp in those months. 21 Q But would you also agree that such large swings in 22 monthly reservation amounts can cause significant 23 differences for a monthly allocation as compared to 24 an annual allocation, and by that, I am referring to 25 the allocations to your next step allocations to rate 26 classes -- 4518 01 A MR. MARTIN: It would cause a difference in 02 the allocation, yes. When these amounts are compared 03 with the other amounts that are being allocated, I am 04 not sure I would consider them significant. But it 05 would cause a difference, yes.
AIPA stated that directionally this causes an over allocation to seasonal summer load in that the summer months receive a higher GENCO amount relative to the non-summer months.
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Other Considerations AIPA stated that in the FIRM Argument in this proceeding on GENCO issues, it was noted that the 2000 electricity market was dysfunctional and subject to pool price manipulation with the result that it was recommended that the Board adjust actual pool prices to deemed pool prices to rectify the harm caused customers. A deemed pool price will directly impact the GENCO deferral accounts by requiring UOV adjustments, such adjustments are proposed to be flowed through to customers via adjustments to the GENCO reservation payments. Since UOVs are integral to the DISCO entitlement sharing process we suggest these anticipated adjustments tend to favour an annual allocation methodology adjustment on the DISCO side for fairness considerations and we understand UNCA is not adverse to this approach as indicated at Tr 4525:
15 Q But your proposal really was predicated on the basis 16 of high Pool prices in the latter part of the year. 17 If there was any change to that, you could revert to 18 the approved U99035 methodology, annual methodology? 19 A MS. KIRRMAIER: It is certainly possible to do 20 the math that way, and presumably if that was 21 smoothed out, if I can use that terminology, it 22 wouldn't make a significant difference whether the 23 monthly or annual basis was used. But yes. We could 24 do it on an annual basis.
Recommended Bottom-Up Approach As indicated previously the AIPA directionally supports a modified UNCA bottom-up methodology for the allocation of pool price deferral account balances.
In terms of the quantum of deferral cost allocation amounts it is illuminating to view the allocation amounts to irrigation service in terms of the different reservation and UOV allocation methodologies. These amounts are summarized below:
Table 21: Allocation Amounts to Irrigation Service (Per AIPA) Irrigation Allocation ($ millions) Annual192 (2.7) Monthly193 0.5 Hourly194 2.9
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This summary shows the directional progression from annual to hourly allocation and the disproportionate impact on the seasonal customer. This summary begs the question of whether another allocation scenario is required which is between the annual and monthly approach. This, the AIPA submits, would be a seasonal allocation that takes into account the 6 summer months
192 Exhibit 386 193 UNCA Application, Schedule 8-A Rev 1, April 24, 2001 194 FIRM, Exhibit 1011
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that the settlement code defines as the deemed consumption profile for irrigation usage and which deemed profile is used as the temporal dispersion of “actual” irrigation consumption. Interpolating from the above summary table suggests that a seasonal allocation would be between an hourly allocation charge of $0.5 million and an annual allocation credit of $2.7 million. Therefore, AIPA stated that it is suggested UNCA and AE be required to provide a seasonal allocation on a required refiling. In the absence of such a refilling, it is submitted that a rough interpolation would place the irrigation allocation, on a seasonal methodology basis, at close to $0 and we submit that this is a reasonable result.
AIPA stated that it is further noted for the Board’s consideration that 2000 pool prices have already had a severe impact on UNCA irrigation service rates. The 2000 pool prices impacted the Transmission Administrator rates which were flowed through to UNCA distribution rates via a rate rider commencing with July 2001 consumption of 1.5c/KWh or an 18% increase to prevailing rates in the current severe drought conditions.
AIPA stated that IPCCAA addresses average UNCA pool purchases during 2000 in their Argument (Section 5, Pool Purchases). The average pool purchase cost for UNCA irrigation is shown as $115.13/MWh but this unit cost relative to the average pool price is not shown. The AIPA considers this comparison should not be omitted and can be calculated as $-18.09/MWh195. This clearly shows the lower irrigation pool purchase costs relative to most other rate classes and directionally supports the AIPA position on irrigation deferral account responsibility.
AIPA stated that IPCCAA addresses irrigation deferral account balances (Argument, Annual UOV Allocation) and suggests that irrigation consumption in August 2000 would get at least $10/MWh in deferral account responsibility. The AIPA disagrees.
AIPA stated that the irrigation load in August 2000 was 23.9 GWh196 or 10.6% of the irrigation seasonal load of 225.8 GWh. Therefore using IPCCAA’s derived $20/MWh cost responsibility for any rate class consumption in August 2000 (using IPCCAA’s assumption of the UNCA load as 10% unhedged in any month and a $200/MWh pool price) the irrigation deferral component would be $2/MWh197 for total seasonal load and not $10/MWh as IPCCAA had calculated. Of course this analysis only addresses the cost side. As AIPA indicated in its Argument, page 5, irrigation rates are overstated in the order of $4.69/MWh relative to average pool prices that were utilized to derive 2000 rates.
AIPA stated that if the IPCCAA analysis is applied to the largest month of irrigation consumption, July 2000, with consumption of 114.5 GWh198 and an average pool price of $124/MWh199 this would give rise to a net deferral responsibility of $6.29/MWh200 or $1.60/MWh after taking the rates difference of $4.69/MWh201 into account.
195 115.13 – 133.22 = - 18.09 196 UNCA Schedule 8-G Rev 1, 24 April 2001, line 4 197 $200/MWh * 10.6% 198 UNCA Schedule 8-G Rev 1, 24 April 2001, line 4 199 UNCA Schedule 2.3, Rev 1, 24 April 2001, line 8 200 ($124 * 10%) * (114.5/225.8) = $6.29/MWh 201 AIPA Argument page 5
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AIPA stated that it should also be recognized that irrigation consumption is subject to profiling and not interval metering. Such profiling is an estimate of irrigation consumption spread out over monthly time periods. Since consumption patterns are heavily dependent on precipitation patterns which vary year-to-year actual 2000 irrigation consumption would have most likely been different from the profile.
In discussing the appropriateness of the UNCA “bottom-up” approach to be applied to AE (Argument page 21), AIPA stated that AE indicated that a major difference from UNCA was that AE rates from April 2000 forward were designed on a bundled basis with a 10% rate cap so that all rate classes did not recover all costs allocated to them. The AIPA notes that UNCA (then TransAlta) was also subject to 10% rate cap considerations on a bundled basis but that the generation component (excluding distribution component) was designed with 100% cost recovery and it is the generation component that is at issue in this proceeding.
AIPA stated that AE suggests (Argument page 21) that it is up to the Board to decide whether the hourly or monthly entitlement deferral allocation method should be standardized. The AIPA notes that its Argument (page 8) addressed the consideration of seasonal and annual allocations to be more consistent with the underlying methodology utilized in developing the original 2000 rates. For instance, for seasonal customers such as irrigation service, the sum of 6 months of Disco UOV refunds could be allocated to this service based on irrigation class consumption relative to total consumption in the same 6-month period. The balance of the UOV refunds could then be allocated to the remaining rate classes as determined by the Board.
AIPA stated that the FIRM Argument states that “the top-down approach provides a greater benefit to customers who curtailed load, or did not consume as much energy during periods of high hourly pool prices” The AIPA notes that this observation is not correct for seasonal load customers. The top-down approach with an hourly UOV allocation is substantially more costly for seasonal customers than the bottom-up with a monthly UOV allocation as provided in this proceeding.
AIPA stated that this detrimental result occurs even though irrigation consumption was at a much lower pool price relative to the average pool price as discussed in the preceding sections of this Reply.
AIPA stated that the ACC presented no direct evidence on this issue. The ACC acknowledges that plausible arguments could be made for either the top-down or the bottom-up approach and would reserve its recommendations for its Reply Argument, after it has had a chance to review the arguments and citations to the evidence made by each party on this issue. Nevertheless, regardless of whether a top-down or a bottom-up approach is used, the ACC opines that the UNC method of allocating the entitlement on a monthly basis is more defensible than the hourly method utilized by ATCO. In the UNC method each MWh consumed in a month gets the same entitlement value per MWh allocated to it, regardless of the hour in which it was used during the month. (Exhibit 440). The ACC believes that this method is more in accord with the underlying principle that entitlement values are a quid pro quo for the fixed reservation payments.
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1.6 Views of SPPA SPPA has reviewed and supports the argument filed by IPCCAA on this section.
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164 • EUB Decision 2002-026 (April 18, 2002)
PART R: AE DISCO UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Accounts Proceeding
Appendix 2 Board Approved Template Deferral Account Formula Component 1 Deferral Account Formula Component 2 Net Deferral G=E+F UNCA Allocation to Rate Class A B C=B/A D E F H=D/A I=B-G J K=IxM22/(M22-J) L M N=L-M O=K-N P=O/O20xB20 Q=P/D R=H+Q +(h factor) Source Ex 373 Sch 8G Ex 373 Sch 8D Ex 323 Ex 373 Sch 8C (Prorate per O) Note 1 Note 2 Note 3 Note 4 Appendix 4 Note 5 Note 6 Note 7 Unadjusted Actual Benefits Outstanding Actual Pool Additional Actual Pool Pool Purchase Received via Deferral Actual Hourly Actual Hourly Actual Energy Purchase Deemed STS Purchase Actual Deemed Adjusted Pool Actual Hourly Entitlement Account Preliminary Per Board Per Board Actual Energy Pool Purchase Pool Purchase at Customer Revenues incl Pool Purchase Revenues excl Interim Collection System Purchase Actual Entitlement portion of H Entitlement Net Collection Final Allocated Per Board Total final Yr Rate Class Rate Purchased Costs Unit Cost Meter H factor Credit Revenues H factor credit Rate Shortfall Benefits Collection Benefits factor Benefit Shortfall Deficiency Deficiency 2000 Energy Description Code GWh $000 $/MWh GWh $000 $000 $000 $/MWh $000 $000 Shortfall $000 $000 $000 $000 $000 $000 Rider $/MWh Rate ($/MWh) 1 Residential 11XX–12XX 2,026 294,827 $145.51 1,904 60,828 3,278 76,860 $40.37 217,967 219,788 233,802 50,536 183,266 36,522 35,184 $18.48 $58.85 2 UNCA Farm 21XX–23XX 626 86,316 $137.78 595 18,172 990 23,147 $38.92 63,170 63,697 68,273 15,786 52,487 11,211 10,800 $18.16 $57.08 3 REA Farm 24XX–25XX 478 64,958 $135.92 454 14,100 753 17,895 $39.42 47,063 47,456 51,308 12,051 39,256 8,200 7,899 $17.40 $56.82 4 UNCA Irrigation 26XX–27XX 226 25,998 $115.13 224 7,705 477 9,686 $43.16 16,312 16,449 20,297 5,957 14,340 2,109 2,031 $9.05 $52.22 5 REA Irrigation 28XX–29XX 2 195 $120.71 2 58 4 72 $44.94 123 124 153 42 110 14 13 $8.23 $53.16 6 Exterior Lighting 3XXX 70 7,493 $107.52 63 1,364 108 1,898 $29.89 5,596 5,642 5,812 1,686 4,127 1,516 1,460 $22.99 $52.88 7 Small General Service 41XX–43XX 1,060 160,181 $151.14 1,000 33,361 1,780 41,841 $41.85 118,340 119,329 127,342 26,542 100,799 18,529 17,850 $17.85 $59.70 8 Pumping 44XX–46XX 815 108,722 $133.36 750 23,073 1,328 29,428 $39.22 79,294 79,956 85,819 19,917 65,902 14,054 13,539 $18.04 $57.27 9 General Service 61XX–62XX 5,286 739,424 $139.88 5,016 155,894 8,979 198,480 $39.57 540,944 545,465 585,192 133,146 452,045 93,420 89,997 $17.94 $57.51 10 Large General Time-of-Use 63XX 2,790 377,753 $135.39 2,735 78,210 96,532 $35.30 281,222 283,572 297,710 72,587 225,123 58,449 56,307 $20.59 $55.89 11 Direct Connected Service 65XX 9,006 1,202,820 $133.56 8,936 254,484 314,353 $35.18 888,467 895,893 949,490 237,197 712,294 183,599 176,872 $19.79 $54.97 12 Direct Access Tariff 68XX 560 103,766 $185.40 560 26,778 30,528 $54.55 73,238 73,850 81,858 14,857 67,001 6,849 6,598 $11.79 $66.33 13 Option G Option G 1,160 99,569 $85.87 1,160 12,536 20,305 $17.51 79,265 20,090 59,670 76,973 30,779 46,194 13,476 12,982 $11.20 $28.71 14 Wholesale Service (Closed) 81XX 115 16,947 $146.82 109 3,505 4,234 $38.92 12,713 12,820 13,459 2,888 10,571 2,249 2,166 $19.91 $58.83 15 Total UNCA — 24,220 3,288,970 $135.80 23,506 690,069 17,698 865,259 $36.81 2,423,711 2,423,711 2,597,487 623,971 1,973,516 450,195 433,699 16 Temporary Energy 339 34,826 339 34,826 34,826 $102.76 $107.25 17 Total UNCA (incl Temp) 24,559 3,323,796 23,845 724,895 900,085 $37.75 Note 1 Actual Pool Purchase Revenues reflect generation rate revenues incl H factor regulated generation credit revenues derived from published rates. Across the board rate riders were not included In the case of DAT and Option G the revenues include pool price revenues less PPA DAT adjustment and GAC Option G adjustment less H factor regulated generation credit The Board has increased actual pool purchase revenues for Option G for Jan 2000 and Feb 2000 to include H factor revenues Note 2 Additional deemed STS Pool Purchase revenues @ $3.00/MWh not included in published rates for rates other than 6300/6400/DAT & Option G (Decision 2000-31) Note 3 H Factor per Rate Schedules -$6.70 Note 4 The unit rate for DAT reflects PPA credit received and the unit rate for Option G reflects GAC credits received. Note 5 The allocation of entitlements was claculated using rate class hourly data from Ex 328 BR.UNCA-1(a,b) and Ex 323 IPPSA/SPPA.UNCA #2-3(a,c) Note 6 Entitlement Portion of H factor $26.54 The Board has not included any received entitlements for Option G for Jan 2000 and Feb 2000 to be consistent with the pool purchase revenue adjustment Note 7 Higher final rate for DAT reflects the fact that almost all energy was purchased in higher price Sep to Dec period In the case of Option G lower final rate reflects the fact that almost all energy was purchased in lower price Jan to Aug period and the deemed system credit. Per Board Prop UNCA Prop UNCA Per UNCA H Factor Per Rate Schedules Unadj Deferral DAT ADJ Opt G Adj Adj Deferral Forecast Sales 22,073 Oct 4,1999 TransAlta 1996 Ph 2 Refiling Entitlements 585,932 Oct 4,1999 TransAlta 1996 Ph 2 Refiling 18 Component 1 Forecast 700,282 16,726 31,249 652,306 Entitlements Component $26.54 19 Actual 3,288,970 103,766 99,569 3,085,635 Reservation Component $19.84 20 Deferral 2,588,689 87,040 68,320 2,433,329 H -Factor (per Rates) -$6.70 21 22 Component 2 Forecast 437,252 190 -6,380 443,442 23 Actual 2,597,487 73,240 81,190 2,443,057 24 Deferral 2,160,235 73,050 87,570 1,999,615 25 26 Net Deferral 428,454 13,994 19,239 433,699 27 PPDA Adj 5,245 28 29 30 31 32 33
EUB Decision 2002-026 (April 18, 2002) Page 1 of 4 PART R: AE DISCO UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Accounts Proceeding
Appendix 2
Board Approved Methodology to determine UNCA Rate Class Deficiency Rider Decision Decision 2002-024 2002-024 Decision Decision Decision Decision Decision Decision Decision Decision Decision Reference Table 6 TSR Table 6 2002-024 2002-024 2002-024 2002-024 2002-024 2002-024 2002-024 2002-023 2002-025 Related GENCO PPDA amounts Receipts
Per Board Per Actual Per Dec 2000 Per Hourly Per Actual Board Approved Per Net DISCO Illustrative Only IIlustrative Illustrative Illustrative Per Rate Class PPDA Decision Annual Energy Pool Entitlement Annual Energy See Note 1 See Note 1 See Note 1 Allocation Method Costs TBD Only TBD Only TBD Only TBD Actual Load 2002-026 Purchased Purchases Adjustments Purchased
Outstanding O/S Matters Forecast Harm Total Revenue Plus 2000 Less 2000 DISCO PPDA 2002 PPDA 2003 PPDA Deferral Acct Energy from Deficiency Per Board Plus Dec 2000 Less GENCO Compensation to be collected Carrying Costs Rider Revenue Balance Jan 1, Carrying Costs Carrying Costs Balance incl Jan 1, 2002 to Rider Allocated Plus VLCP Power Pool Plus EV Deferral Net DISCO incl Carrying by rate class $000 $000 2002 $000 $000 Carrying Costs Dec 31, 2003 $MWh Rate Class Rate Deficiency Costs Uplift Costs Adjustments Amounts Costs Costs $000 $000 $000 $000 GWh Description Code $000 $000 $000 $000 $000 $000 1 Residential 11XX–12XX 35,184 194 8 4,301 -5,285 34,402 543 -7,330 27,616 794 181 199 -330 28,460 3,808 $7.47 2 UNCA Farm 21XX–23XX 10,800 60 2 1,256 -1,634 10,484 166 -2,358 8,292 238 54 61 -98 8,548 1,189 $7.19 3 REA Farm 24XX–25XX 7,899 46 2 944 -1,247 7,644 121 -1,724 6,041 174 40 45 -74 6,225 908 $6.86 4 UNCA Irrigation 26XX–27XX 2,031 22 1 373 -589 1,838 29 -786 1,081 31 7 12 -31 1,100 449 $2.45 5 REA Irrigation 28XX–29XX 13 0 0 3 -4 12 0 -4 8 0 00083$2.57 6 Exterior Lighting 3XXX 1,460 7 0 107 -182 1,392 22 -186 1,228 35 8 8 -9 1,271 127 $10.01 7 Small General Service 41XX–43XX 17,850 102 4 2,343 -2,764 17,534 277 -3,984 13,827 397 91 101 -178 14,239 2,000 $7.12 8 Pumping 44XX–46XX 13,539 78 3 1,579 -2,126 13,072 206 -2,923 10,356 298 68 77 -124 10,674 1,501 $7.11 9 General Service 61XX–62XX 89,997 507 19 10,766 -13,789 87,500 1,381 -22,914 65,967 1,896 433 510 -835 67,971 10,032 $6.78 10 Large General Time-of-Use 63XX 56,307 267 10 5,477 -7,278 54,784 865 -10,568 45,081 1,295 296 319 -433 46,559 5,469 $8.51 11 Direct Connected Service 65XX 176,872 863 32 17,468 -23,492 171,743 2,711 -39,682 134,772 3,873 885 1,003 -1,371 139,162 17,871 $7.79 12 Direct Access Tariff 68XX 6,598 54 3 1,506 -1,460 6,701 106 0 6,806 196 45 37 -119 6,965 1,119 $6.22 13 Option G Option G 12,982 111 3 1,416 -3,025 11,487 181 0 11,669 335 77 74 -122 12,032 2,319 $5.19 14 Wholesale Service (Closed) 81XX 2,166 11 0 248 -301 2,124 34 -446 1,712 49 11 12 -19 1,765 218 $8.11 15 Total per Board — 433,699 2,321 86 47,788 -63,176 420,718 6,642 -92,904 334,456 9,611 2,197 2,459 -3,743 344,980 47,013
Note 1 These columns are shown for illustrative purposes only. UNCA ,in their refiling, should identify the revenues already collected under the interim rider and then develop rider using remaining revenues to be collected divided by remaining forecast consumption to Decemeber 31, 2003
EUB Decision 2002-026 (April 18, 2002) Page 2 of 4 PART R: AE DISCO UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Accounts Proceeding
Appendix 2
Board Approved Deferral Account Formula Component 2 Net Deferral AE Allocation to Rate Class A B C=B/A D E F=E+(h factor) G=F/D H=B-F I J K=I-J L=H-K M=L/L20xF38 N=M/D O=G+N Exhibit 407-3 Illustrative only Illustrative only (Prorate per L) Cost of Actual Benefits Outstanding Forecast Forecast Forecast Forecast Pool Forecast Pool Received via Deferral Energy at Hourly Pool Energy at Purchase Purchase Actual Hourly Entitlement Account Preliminary Per Board Per Board Forecast Actual Hourly Purchase Customer Revenues incl Revenues excl Interim Collection Entitlement portion of H Entitlement Net Collection Final Allocated Per Board Total final Yr Rate Class Rate Energy Pool Price Unit Cost Meter H factor Credit H factor credit Rate Shortfall Benefits factor Benefit Shortfall Deficiency Deficiency 2000 Energy Description Code MWh $000 $/MWh GWh $000 $000 $/MWh $000 $ 000 $ 000 $000 $000 $000 Rider $/MWh Rate ($/MWh) 1 Residential 11 795,293 117,737 105,444 6,279 2 Commercial 21,22 763,753 106,753 95,607 5,694 3 Irrigation 25,26 2,852 179 160 10 4 >=2 MW D-Connect Ind. Fixed Rate Energy 31x 2,298,704 294,349 263,617 15,699 5 <2 MW D-Connect Ind. Fixed Rate Energy 31x 2,892,738 377,728 338,291 20,146 6 >=2 MW T-Connect Ind. Fixed Rate Energy 31x 2,259,355 307,264 275,183 16,388 7 <2 MW T-Connect Ind. Fixed Rate Energy 31x 16,101 2,197 1,967 117 8 Oilfield 41 460,953 61,009 54,639 3,254 9 REA Farm 51 175,541 26,094 23,370 1,392 10 Company Farm 56 300,491 44,668 40,004 2,382 11 Street Lighting 61 20,110 2,896 2,594 154 12 Private Lighting 63 4,401 634 568 34 13 DAT (Note 1) 39D,39T,49 Not Available 13 Total Energy 9,990,291 1,341,508 Not Available 1,201,445 71,549 14 POR Not Available 15 Total Energy Not Available
Note 1 : AE to treat all DAT customers as a separate rate class for the purposes of the allocation of the PPDA
Deferral Acct
Component 1 Forecast 298,717 Actual 1,341,508 Deferral 1,042,790
Component 2 Forecast 230,203 Actual 1,201,445 Deferral 971,241
Net Deferral 71,549
EUB Decision 2002-026 (April 18, 2002) Page 3 of 4 PART R: AE DISCO UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Accounts Proceeding
Appendix 2
Board Approved Methodology to determine AE Rate Class Deficiency Rider Decision Decision Decision Decision Decision Decision Decision Decision Decision Decision Decision Reference 2002-024 2002-024 2002-024 2002-024 2002-024 2002-024 2002-024 2002-024 2002-024 2002-023 2002-025 Directly Per Board Per Dec 2000 Per Hourly Per Forecast Per Actual Per DISCO Assigned to Illustrative Illustrative Illustrative Per Rate Class Board Approved Allocation Method PPDA Decision Pool Entitlement Annual Energy Annual Energy PPDA DAT Rate Only TBD Only TBD Only TBD Actual Load 2002-26 Purchases Adjustments Class Outstanding O/S Matters Harm Forecast Total Revenue Per Board Plus Dec 2000 Plus POR Less DAT DISCO PPDA 2002 PPDA 2003 PPDA Deferral Acct Compensation Energy from Deficiency to be collected Allocated Plus VLCP Power Pool Plus EV Less GENCO Deferral Adjustment Balance Jan 1, Carrying Costs Carrying Costs Balance incl incl Carrying Jun 1, 2002 to Rider by rate class Rate Class Rate Deficiency Costs Uplift Costs Adjustments Deferral $000 $000 2002 $000 $000 Carrying Costs Costs May 31, 2003 $MWh $000 Description Code $000 $000 $000 $000 Amounts $000 $000 $000 $000 MWh 1 Residential 11 6,279 84 3 2,117 -2,298 1,156 -8 7,107 161 39 347 -132 7,522 795,293 $9.46 2 Commercial 21,22 5,694 81 3 1,920 -2,207 1,049 -7 6,444 146 35 315 -120 6,820 763,753 $8.93 3 Irrigation 25,26 10003-820110010112,852 $4.01 4 >=2 MW D-Connect Ind. Fixed Rate Energy 31x 15,699 244 8 5,293 -6,643 2,891 -21 17,769 403 96 867 -330 18,806 2,298,704 $8.18 5 <2 MW D-Connect Ind. Fixed Rate Energy 31x 20,146 307 10 6,792 -8,360 3,710 -26 22,802 518 124 1,113 -423 24,133 2,892,738 $8.34 6 >=2 MW T-Connect Ind. Fixed Rate Energy 31x 16,388 240 8 5,525 -6,530 3,018 -22 18,548 421 101 905 -344 19,631 2,259,355 $8.69 7 <2 MW T-Connect Ind. Fixed Rate Energy 31x 117 2 0 39 -47 22 0 133 3 1 6 -2 140 16,101 $8.72 8 Oilfield 41 3,254 49 2 1,097 -1,332 599 -4 3,683 84 20 180 -68 3,898 460,953 $8.46 9 REA Farm 51 1,392 19 1 469 -507 256 -2 1,575 36 9 77 -29 1,667 175,541 $9.50 10 Company Farm 56 2,382 32 1 803 -868 439 -3 2,696 61 15 132 -50 2,854 300,491 $9.50 11 Street Lighting 61 154 2 0 52 -58 28 0 175 4 1 9 -3 185 20,110 $9.20 12 Private Lighting 63 34 0 0 11 -13 6 0 38 1 0 2 -1 40 4,401 $9.20 13 DAT 39D,39T,49 Not Available 13 Total Energy 71,549 1,061 37 24,123 -28,872 13,177 -94 80,981 1,838 439 3,953 -1,503 85,708 9,990,291 14 POR Not Available 15 Total Energy Not Available
EUB Decision 2002-026 (April 18, 2002) Page 4 of 4 PART R: AE DISCO UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Accounts Proceeding
UtiliCorp Networks Canada (Alberta) Ltd.
Per Board Calculation of Deemed System Cost and Average Pool Purchase Cost
Line: Column: A B C D E=C-D F G=ExF H I=H-G
Rate 6300 and Deemed System Option G/21 Credit Payment 6500 Base Option G/21 Benefit Energy Firm Load Required for Required for Actual Actual Pool Load Energy Energy (I.e.Additional 1 Month Purchased Price Revenue Revenue GAC Credits Price ($/MWh) Purchased Purchased Credit Received Cost ($/MWh) Neutrality Neutrality ($ million) Cost (GWh) for Curtailments) ($/MWh) ($/MWh) ($ million) ($/MWh) ($millions)
2 Jan-00 46.46 46.49 44.85 33.18 11.67 142.6 1.66 3.58 1.92 3 Feb-00 47.07 46.99 45.99 33.18 12.81 144.2 1.85 3.78 1.93 4 Mar-00 77.19 76.94 71.46 33.18 38.28 154.6 5.92 7.26 1.34 5 Apr-00 93.68 93.97 84.72 33.18 51.54 146.1 7.53 9.97 2.43 6 May-00 51.66 51.54 50.13 33.18 16.95 143.8 2.44 3.04 0.61 7 Jun-00 106.73 106.77 97.75 33.18 64.57 143.8 9.28 11.67 2.38 8 Jul-00 124.11 123.68 113.09 33.18 79.91 142.0 11.35 14.54 3.20 9 Aug-00 202.09 201.63 181.21 33.18 148.03 142.3 21.07 27.35 6.28 10 Sep-00 11 Oct-00 12 Nov-00 13 Dec-00 14 2000 1,159.5 61.10 81.19 20.09
EUB Decision 2002-026 (April 18, 2002) Page 1 of 2 PART R: AE DISCO UNCA DISCO ALLOCATION TO RATE CLASS 2000 Pool Price Accounts Proceeding
Appendix 4
UtiliCorp Networks Canada (Alberta) Ltd. Per Board Calculation of Average Pool Purchase Cost
Line: Column: A B C D E=B-C F=ExD
Effective DAT Energy Effective DAT Energy Actual Pool Price Cost of DAT Energy Actual 'PPA' DAT Energy 1 Month Purchased Cost Purchased Cost ($/MWh) Purchased ($/MWh) Credits ($/MWh) Purchased (GWh) ($/MWh) ($Millions)
2 Jan-00 46.46 46.26 15.48 15.3 30.79 0.47 3 Feb-00 47.07 45.75 21.25 14.5 24.50 0.36 4 Mar-00 77.19 57.80 38.20 3.7 19.60 0.07 5 Apr-00 93.68 95.06 50.37 2.8 44.69 0.13 6 May-00 51.66 47.31 13.86 3.2 33.45 0.11 7 Jun-00 106.73 71.50 53.96 1.3 17.55 0.02 8 Jul-00 124.11 68.41 84.17 1.4 -15.75 -0.02 9 Aug-00 202.09 108.83 146.37 0.5 -37.54 -0.02 10 Sep-00 176.28 162.23 117.73 120.0 44.51 5.34 11 Oct-00 253.28 237.53 165.42 134.2 72.11 9.68 12 Nov-00 227.73 207.10 158.29 128.1 48.80 6.25 13 Dec-00 188.91 176.18 115.91 133.7 60.26 8.05 14 2000 133.22 558.8 $54.48 30.44
EUB Decision 2002-026 (April 18, 2002) Page 2 of 2