Decision 2001-115: 2000 Pool Price Deferral Accounts …€¦ · amend Directions Numbers 6 and 7...

DECISION 2001-115

2000 POOL PRICE DEFERRAL ACCOUNTS PROCEEDING

PART N: AMENDMENT OF DECISION 2001-95 RESPECTING THE

TIMING OF EGI GENCO PAYMENT TO DISCOS/TA AND CORRECTED VIEWS OF THE BOARD DEALING WITH EGI GAS UNITS SHARING

EUB Decision 2001-115 (December 27, 2001)

ALBERTA ENERGY AND UTILITIES BOARD 2000 Pool Price Deferral Accounts Proceeding

2000 POOL PRICE DEFERRAL ACCOUNTS PROCEEDING PART N: AMENDMENT OF DECISION 2001-95 RESPECTING THE TIMING OF EGI

GENCO PAYMENT TO DISCOS/TA AND CORRECTED VIEWS OF THE BOARD RESPECTING EGI GAS UNITS SHARING

CONTENTS

1 INTRODUCTION AND BACKGROUND ......................................................................... 1

2 REASONS FOR PROVIDING RELIEF FROM TIMING OF EGI PAYMENT........... 2

3 AMENDED DIRECTIONS RESPECTING TIMING OF EGI PAYMENT .................. 3

4 AMENDED VIEWS OF THE BOARD RESPECTING SECTIONS 4.2.2 AND 4.3 OF DECISION 2001-95............................................................................................................... 4 4.1 Introduction ................................................................................................................. 4 4.2 Views of the Board - EGI GENCO Gas Units Deferral Account Sharing.................. 4

4.2.1 Views of the Board - Expectations for Variances from Changed Formula ....... 5 4.2.2 Corrected Views of the Board - Surplus – Improved Performance vs. Higher

Pool Price ...................................................................................................... 6 4.2.3 Views of the Board - Additional EGI Costs – Delay of Planned Outages....... 13

4.3 Corrected Summary - Board Approved Sharing of Gas Units Deferral Account ..... 14

5 CORRECTION TO APPENDIX 2 OF DECISION 2001-95 .......................................... 16

6 AMENDED SUMMARY OF APPROVALS AND CONCLUSIONS ............................ 16

7 APPENDIX 2 - EGI GAS UNITS DEFERRAL ACCOUNT SHARING PER BOARD............................................................................................................................................... 19

LIST OF TABLES

Table 6: Corrected Board Approved - Sharing Resulting from Peak Hour Outage Frequency................................................................................................................. 12

Table 7: Corrected Board Approved Sharing of EGI Gas Units Deferral Account ........ 16

EUB Decision 2001-115 (December 27, 2001) • i

ALBERTA ENERGY AND UTILITIES BOARD Calgary, Alberta 2000 POOL PRICE DEFERRAL ACCOUNTS PROCEEDING PART N: TIMING OF EGI GENCO PAYMENT AND CORRECTED EGI GAS UNITS SHARING VIEWS OF THE BOARD

Decision 2001-115Amendment to Decision 2001-95

Application & File Nos.1

1 INTRODUCTION AND BACKGROUND

The Board issued Decision 2001-95 on December 22, 2001 in which it dealt with the disposition of TransAlta GENCO, AE GENCO and EGI’s December 31, 2000 Deferral Account balances. In Decision 2001-95, the Board directed EGI to make a final payment to the DISCOs and the TA on or before December 31, 2001. On December 24, 2001, Mr. Robert Heggie, the Board’s Executive Manager of the Utilities Branch, received a telephone call from Mr. Stephen Muir, Vice President and Treasurer of EPCOR requesting relief from the Board direction requiring EGI to make its final payment to the DISCOs and the TA on or before December 31, 2001. Given the urgency and special circumstances of this request, Mr. Heggie conferred with the Division of the Board assigned to review and decide the Year 2000 Pool Price Deferral Account Applications (Panel). The Panel decided that a measure of relief could be granted to EGI. Therefore, acting on the Panel’s direction, Mr. Heggie sent the following letter to Mr. Muir on December 24, 2001:

Pursuant to our telephone conversation of today’s date EPCOR Generation Inc. (EGI) has requested relief from a direction in the above captioned decision to pay to entitled Discos $23,362,000.00 by December 31, 2001. I am directed to advise you that the Board has amended its decision by allowing EGI to comply with this direction as soon as possible. Be advised that such payment should include interest as calculated pursuant to Board Decision 2001-92.

The Board, in this amending Decision, will provide the reasons for the amendment to the Board’s Directions respecting the timing of EGI’s final payment to the DISCOs/TA as well as the interest rate to be used. Further, in reviewing Decision 2001-95, the Board has observed that it included in that Decision an incorrect version of the Views of the Board in Sections 4.2.2 and 4.3 respecting EGI GENCO Gas Units Deferral Account Sharing. Accordingly, the Board, in this amending Decision will include the correct version of the Views of the Board.

1 TransAlta Utilities Corporation, Application No. 2001059, File 1207-7-5; ATCO Electric Ltd., Application No. 2001061, File 1108-9; EPCOR Generation Inc., Application No. 2001063, File 1705-1.

EUB Decision 2001-115 (December 27, 2001) • 1

PART N: AMENDMENT OF DECISION 2001-95 RESPECTING THE TIMING OF EGI GENCO PAYMENT

2000 Pool Price Deferral Accounts Proceeding

The amendments to Sections 4.2.2 and 4.3 do not change the Board’s findings that the EGI GENCO Gas Units Deferral Account should be shared 80% customers/20% shareholders or the amount of the final payment of $23,362,000 dollars required to be made by EGI. However, the amendment reflects the correct reasoning of the Board to arrive at these findings. The Board apologizes for any inconvenience that these amendments may have caused interested parties. 2 REASONS FOR PROVIDING RELIEF FROM TIMING OF EGI PAYMENT

The Board recognizes that EGI was required to make a much larger payment to the DISCOs and the TA than either TransAlta DISCO or AE GENCO. The Board also recognizes that issuing Decision 2001-95 on December 22, 2001 only provided EGI with four working days to make the financial arrangements for the large final payment. One of the Board’s reasons for directing payments on or before December 31, 2001 was provided on page 88 of Decision 2001-95 as follows:

Therefore, the Board considers that the final, Board-approved GENCO balances should be paid to the DISCOs and the TA as soon as possible to reduce DISCO carrying charges.

The Board also considered that it would be of assistance to the GENCOs and DISCOs to be provided with the amount of the payments prior to the closing of 2001 year-end financial statements. The Board considers that although it may be an inconvenience to the DISCOs and the TA not to receive EGI’s payment on or before December 31, 2001, the forthcoming amount from EGI can nevertheless be shown as an accrual on 2001 year-end financial statements. The Board considers that the DISCOs and the TA will be kept whole, including DISCO carrying charges, by allowing EGI to make its payment to the DISCOs and the TA after December 31, 2001 provided EGI is required to include further interest payments for the period of time between December 31, 2001 and the date that the final payment is made in the year 2002. In Decision 2001-92, the Board approved an EGI carrying cost rate of 7.08% for 2001 and 5.77% for the first quarter of 2002. However, in this particular circumstance, the Board considers that EGI should make the further interest payments for the period of time between December 31, 2001 and the date that the final payment is made at the 2001 rate of 7.08% to ensure the DISCOs are kept whole. The Board notes that the 2001 carrying cost rate of 7.08% for EGI exceeds the Board approved before tax carrying cost rate of 6.45% approved for the investor-owned DISCOs for the first quarter of 2002. Accordingly, the Board considers that requiring EGI to use the 7.08% carrying

2 • EUB Decision 2001-115 (December 27, 2001)



cost rate will keep the investor-owned DISCOs whole. The Board does not have any jurisdiction to determine the 2002 carrying cost rate for the municipally owned DISCOs but observes that the 7.08% carrying cost rate is equal to the after tax carrying cost rate that the Board approved for the municipally owned DISCOs for the year 2001. Accordingly, the Board considers that requiring EGI to use the 7.08% carrying cost rate will keep the investor-owned DISCOs whole. The Board notes that the 7.08% translates into a daily rate of 0.0193973% (i.e. 7.08% divided by 365 days). Consistent with the simple interest calculations approved in Decision 2001-95, the Board considers that EGI should calculate the further interest payments by multiplying the number of days between December 31, 2001 and the date that the final payment is made by the daily rate of 0.0193973%. The Board considers that the additional interest charges should be allocated to the DISCOs and the TA as per the 2000 Reservation Payment shares shown on Schedule 3 of Decision 2001-95. Accordingly, for all of the above reasons, the Board considers that it would be appropriate to amend Directions Numbers 6 and 7 in Decision 2001-95 that deal with the timing of the EGI payment to the DISCOs and the TA. Direction Number 6 (Decision 2001-95 page 87) currently reads as follows:

The Board directs EGI to make a payment of $23.362 million dollars to the DISCOs and the TA as set out in attached Schedule 3 on or before December 31, 2001. This amount represents the final balance for EGI’s 2000 Pool Price Deferral Account and includes the amount associated with the revised sharing of the gas units Deferral Account.

Direction Number 7 (Decision 2001-95 page 88) currently reads as follows:

Accordingly, the Board directs TransAlta GENCO, AE GENCO and EGI to pay their final Deferral Account balances as approved by the Board in this Decision to the entitled DISCOs on or before December 31, 2001.

3 AMENDED DIRECTIONS RESPECTING TIMING OF EGI PAYMENT

The Board hereby amends Direction 6 of Decision 2001-95 to read as follows:

The Board directs EGI to make a payment of $23.362 million dollars to the DISCOs and the TA as set out in attached Schedule 3, as soon as possible, but no later than January 10, 2002. This amount represents the final balance for EGI’s 2000 Pool Price Deferral Account and includes the amount associated with the revised sharing of the gas units Deferral Account. EGI should also include a payment representing interest charges calculated at a daily rate of 0.0193973% for the period of time between December 31, 2001 and the date




that the final payment is made. The additional interest charges shall be allocated to the DISCOs and the TA as per the 2000 Reservation Payment shares shown on Schedule 3 of Decision 2001-95. EGI is further directed to include its calculation of the additional interest charges in its January 10, 2002 refiling. (Amendment emphasized)

The Board hereby amends Direction 7 of Decision 2001-95 to read as follows

Accordingly, the Board directs TransAlta GENCO, AE GENCO and EGI to pay their final Deferral Account balances as approved by the Board in this Decision to the entitled DISCOs on or before December 31, 2001. In the case of EGI, the payment shall be made on or before January 10, 2002. (Amendment emphasized)

4 AMENDED VIEWS OF THE BOARD RESPECTING SECTIONS 4.2.2 AND 4.3 OF DECISION 2001-95

4.1 Introduction As noted earlier, the corrected version of Sections 4.2.2 and 4.3 does not change the Board’s findings that the EGI GENCO Gas Units Deferral Account should be shared 80% customers/20% shareholders or the amount of the final payment of $23,362,000 dollars required to be made by EGI. However, the amendment reflects the correct reasoning of the Board to arrive at these findings. Although the wording changes are not extensive, the correct text of the Views of the Board respecting Sections 4.2 and 4.3 are reproduced in their entirety in this amending Decision for the convenience of readers. Accordingly, the Board hereby amends Sections 4.2.2 and 4.3 of Decision 2001-95 to read as shown in the following views of the Board respecting EGI GENCO Gas Units Deferral Account Sharing. The amendments are bolded and shown in a larger font for the convenience of readers. 4.2 Views of the Board - EGI GENCO Gas Units Deferral Account Sharing The Board has been asked to vary Decisions U99099 and 2000-5 as they apply to the sharing mechanisms established by the Board for EGI’s gas units deferral account. As required by section 57(2)(c) of the EU Act, the Board must be satisfied that there has been a substantial and unforeseen change in the circumstances that led to these aspects of Decisions U99099 and 2000-5 that has rendered the sharing formula for EGI’s gas unit deferral accounts unjust and unreasonable.




The Board has addressed these issues by breaking them down into the following subsections: (click on the points below to hyperlink to the sections)

• Expectations for Variances in Gas Units from Changed Formula 2000-5 • Surplus – Improved Performance vs. Higher Pool Price Effects • Additional Costs Incurred by EGI – delay of planned outages • Summary - Board Approved Sharing of Gas Units Deferral Account

4.2.1 Views of the Board - Expectations for Variances from Changed Formula The first question the Board must determine is whether there has been a substantial and unforeseen change in the circumstances that led to its original Decisions U99099 and 2000-5. In Decision U99099, the Board originally approved a “100% customer/0% EGI” sharing of EGI’s pool price deferral account and a “90% customer/10% EGI” sharing of the ancillary services deferral account for EGI’s gas units. At the time of EGI’s 1999/2000 refiling, the Board was persuaded to set up a unique deferral account for EGI gas units, which resulted in the change to the 50/50 sharing mechanism approved in Decision 2000-5. In Decision 2000-5, the Board established the basis for EGI’s unique deferral account as follows:

The Board notes from EPGI’s refiling that the forecast generation from EPGI’s gas units are less than 6% for 1999 and less than 3% for 2000 of the total provincial supply. The Board also notes EPGI’s comment in its January 20, 2000 letter that EPGI is likely to experience only comparatively small forecast variances.

Consequently, the Board considers that it would be appropriate to determine a unique deferral account approach for gas units. The Board notes that with gas units being dispatched on the margin, volume and price variances from forecast would tend to go hand in hand and generally be unrelated to generator performance. In other words, higher than forecast pool prices would generally result in higher than forecast volumes and lower than forecast pool prices would generally result in lower than forecast volumes.2

Most importantly, the Board clearly stated that the intent of the “50% customer/50% EGI” sharing would not dampen incentives, but would safeguard against windfall gains that have little to do with performance:

The Board considers it appropriate that the deferral account simply capture differences between the gas units’ forecast and actual surplus/shortfall, including ancillary services, and that the annual difference be shared on the basis of 50 per cent to customers and 50 per cent to shareholders. The Board

2 Decision 2000-5, page 7 [emphasis added]




considers that this sharing will not inappropriately dampen the hour by hour incentives and will also safeguard against inappropriate windfall gains or losses that have little to do with generation performance. The Board also considers that this sharing will not disturb the Board’s findings on fair return for EPGI as the annual variance to be shared is expected to be relatively small.3

As the Board also noted in Decision 2001-45:4

The Board agrees with EGI’s statement “it is obvious that the events of 2000 were not foreseen by the Board or any of the parties who participated in the Hearing that gave rise to Board Decision U99099 and the subsequent related Board Decisions.” The Board also agrees with EGI’s argument that this unforeseen turn of events, in itself, is not necessarily a sufficient basis for review and variance.

Further, the Board agrees with EGI that the public interest requires that all parties have confidence in both the Board and the regulatory process. In particular, the Board agrees that public confidence in the Board’s process and decisions could be severely eroded if Board decisions are subject to R&V simply as a result of the fact that actual events turn out to be different than originally forecast.

The Board affirms that, at the time it approved the 50/50 sharing formula in Decision 2000-5, its expectations, based on information provided primarily by EPGI, were that the variations were expected to be small. The Board also expected that, for the most part, EGI gas units would have been dispatched on the margin. The Board notes that, while EGI’s units were on the margin part of the time, they were inframarginal (below the pool price) for a much larger portion of the time than was expected. In addition, the Board notes that the spread between gas prices and the forecast pool prices were significantly higher in 2000 than at the time the sharing formula was established in Decision 2000-5. Based on the evidence in this proceeding, the Board finds that the variances from forecast were anything but small and were certainly not foreseen at the time Decisions U99099 and 2000-5 were made. Therefore, the Board concludes that the large surplus of $69.8 million in the EGI gas units deferral account represents a substantial and unforeseen change in circumstances that led to Decision 2000-5. (Click here for Quick Hyperlink to return to start of Board Views regarding EGI Gas Units Sharing.) 4.2.2 Corrected Views of the Board - Surplus – Improved Performance vs. Higher Pool Price

Having concluded that the surplus of $69.8 million is substantial and unforeseen, the Board must consider whether, in light of that circumstance, the sharing formula approved in Decision

3 Decision 2000-5, page 8 [emphasis added] 4 Decision 2001-45, page 25 [footnotes omitted]




2000-5 is no longer just and reasonable. If the Board so concludes, it may exercise its discretion to vary that Decision as appropriate in order to remedy the unjust and unreasonable situation. The Board acknowledges that these deferral accounts were established precisely to deal with the uncertainty of pool prices over the forecast period during the transition to a fully competitive electricity supply market. However, the Board does not agree that the deferral account sharing mechanisms are immutable, particularly in light of the significantly higher pool prices that occurred in 2000 over those forecast at the time the sharing mechanisms were determined by the Board to be appropriate. On one hand, the Board does agree that EGI should be entitled to share in the benefits realized by virtue of the incentives that were intended by the Board in establishing its gas units deferral account and the sharing mechanism approved in Decision 2000-5. In the Board’s view, to the extent that the Board is satisfied that the surplus realized in EGI’s gas units deferral account were the result of EGI’s improved performance (which would reflect the incentive intended by the Board in establishing the deferral accounts and sharing mechanisms) rather than simply due to higher pool prices, the change in circumstances leading to the surplus does not render the sharing mechanism unjust and unreasonable. However, on the other hand, to the extent that the Board is satisfied that the surplus is not the result of improved EGI performance, the Board considers EGI’s share of the surplus to represent a windfall gain that was never contemplated by the Board when it established the sharing mechanism. To that extent, the Board considers the sharing mechanism to lead to an unjust and unreasonable result that should be remedied by varying the sharing mechanism appropriately. Therefore, the Board must determine whether the large surplus in EGI’s gas units deferral account resulted solely from improved EGI performance due to the incentives provided by the deferral account formula or whether a component of the surplus resulted from an unintended windfall gain as a consequence of higher than expected pool prices. As noted in Section 2 of this Decision, in making this determination, the Board is mindful of the desire for regulatory certainty and the need to treat all parties fairly. The Board must distinguish between the increased surplus resulting from improved EGI performance that should flow to EGI shareholders as opposed to the increased surplus that was unintended and arose from unanticipated higher pool prices that should be shared with customers. To make this determination, the Board will analyze the increased EGI gas unit generation in the year 2000 to determine the components as follows:

a. The component due to improved performance, and b. The component due to units being called on more often due to higher than forecast pool

prices. Accordingly, the Board considers it important to first deal with EGI’s claim that “substantially




all” of the $69.8 million surplus is attributable to “EGI’s improved performance statistics”.5 In Reply Argument, EGI stated the following:

IPCCAA fails to acknowledge that surplus/shortfall is a function of both unit performance and pool price, not just pool price. IPCCAA’s refusal to acknowledge these facts results in IPCCAA wrongly focusing its arguments on absolute changes in unit output relative to forecast that are attributable to both improved performance and the units being called on more often. Instead, the relevant issue is the impact of improved performance on EGI’s surplus/shortfall position.

In its Reply Argument, IPCCAA stated the following:

EGI claims that “substantially all” of the $70 million surplus can be attributed to “EGI’s improved performance statistics” (EGI Argument, Page 9). If by “performance” EGI means that the units ran more often because the Pool Price exceeded gas-fired energy costs, then this is correct. But if EGI means that the increased availability (or, more precisely, decreased FMOR) was the reason, it is clearly wrong. As demonstrated in IPCCAA’s initial Argument (Page 20), Rossdale 10 performed worse than forecast, but enjoyed a substantial surplus instead of a shortfall.6

The Board considers it to be normal and expected that when the actual pool price exceeds the incremental costs to generate electricity from the gas-fired units then, to the extent that they are available; EGI’s gas units would run. When this situation occurs more often than was forecast, then EGI’s gas units would also run more often than forecast. As the Board has found, the actual pool price was significantly different than forecast, leading the Board to conclude that increases in the deferral account surplus attributable to this kind of behaviour are not due to EGI’s performance, but are windfall in nature. In changing the deferral account sharing formula in Decision 2000-5, the Board clearly intended to “safeguard against inappropriate windfall gains or losses that have little to do with generation performance.”7 To the extent that the surplus in EGI’s accounts represent windfall gains, the Board considers that the 50/50 sharing mechanism approved in Decision 2000-5 is no longer just and reasonable and should be varied. Having regard to these considerations, the Board concludes that the portion of the deferral account that is due to the increase in pool price alone and absent an increase in performance statistics, should properly be allocated to customers.

5 EGI Argument page 9 6 IPCCAA Reply page 7 7 Decision 2000-5, page 8




Accordingly, in order to give effect to this intent, the Board considers that the 50/50 sharing of the component of the increased surplus resulting from EGI units being called on more often is not appropriate. This is because it would not achieve the intent of the Decision 2000-5 revisions to the deferral account to safeguard against inappropriate windfall gains or losses that have little to do with generation performance. However, the Board notes EGI’s claims that the 50/50 sharing scheme created “strong financial incentives for EGI to take actions, take calculated risks and incur costs” to achieve higher financial rewards. As already noted, the Board agrees that EGI should be entitled to share in the gains realized due to improved performance by virtue of the incentives inherent in the establishing of its deferral account and associated sharing formula. Accordingly, the Board considers that the sharing formula should appropriately recognize the increased surplus/shortfall due to improved performance since EGI made all performance-related decisions throughout the year 2000 with the understanding that the deferral account would be shared 50/50. The Board considers this approach to be fair to EGI and that it maintains regulatory consistency. In that regard, IPCCAA acknowledged that the reliability of EGI’s gas units (as measured by FMOR) was better in the year 2000 than the three-year average used to establish the forecast. However, IPCCAA claimed that the lower FMOR achieved by EGI accounted for only a small portion of the increased generation and, hence, the deferral account surplus. The Board considers that the deferral account component due to “improved performance statistics” can be measured by the increased availability (i.e. decreased FMOR) for EGI gas units. The Board notes that IPCCAA measured this component to be 582 GWh out of the total increased generation (actual over forecast) of 3097 GWh. At page 3 of 4 of Appendix 2 of this Decision, the Board has made its own assessment of the impact of decreased FMOR for EGI’s gas units in 2000 and has calculated the corresponding increased availability to be approximately 317 GWh. In arriving at its estimate, the Board has applied the change in FMOR directly to the in-merit generation of each unit in order to arrive at this value. The Board is unable to reconcile its calculation of 317 GWh with the 582 GWh provided by IPPCCA. Nevertheless, the Board notes that the difference between the total increased generation (actual over forecast) for the year 2000 of 3097 GWh and either 582 GWh or 317 GWh is substantial. As noted below, since the Board does not consider changes to planned maintenance to be indicative of improved performance of the generating unit, the Board has excluded planned outages from its calculations in on pages 1 to 3 of Appendix 2. The Board will deal with the impact of planned outages separately, later in this section. The Board notes the substantial disagreement among parties respecting the appropriate way to quantify the effect on the deferral account surplus of the increased availability of EGI’s gas units in year 2000. EGI suggested that surplus/shortfall is a function of both unit performance and pool price, not




just pool price. EGI noted that increased pool prices (or increased spreads between pool prices and gas prices) result in higher surpluses during unit operation and higher shortfalls during forced or planned outages. EGI claimed that its PROSYM 2000 simulation demonstrated, among other things, that, had the actual FMORs for EGI’s gas units turned out to be equal to the higher forecast FMOR, EGI’s actual surplus/shortfall position would have been reduced by $65.9 million, notwithstanding that the year 2000 was a higher priced environment than forecast. In EGI’s view, this result clearly demonstrated that EGI’s success in reducing the actual FMORs of these units from forecast was the primary cause of EGI’s actual surplus above forecast in the higher priced environment of the year 2000. In contrast, IPCCAA submitted as an example that, when Rossdale 10’s performance is measured by availability statistics, it performed worse than forecast. However, using the deferral account formula, it enjoyed a substantial surplus instead of a shortfall.8 EGI refuted this argument by noting the following:

The performance of Unit 10 and its resulting surplus/shortfall position merely suggests that Unit outages generally occurred during periods of lower pool prices, while the Unit was generally operating during periods of higher pool prices.9

The Board accepts EGI’s explanation respecting the Rossdale 10’s performance statistics. The Board considers that the results for Rossdale 10 would appear to be consistent with the incentive provided by the deferral account formula to run during periods of high pool price and attempt to confine outages to periods of low pool price. The Board notes that EGI, in its PROSYM simulation, arrived at a surplus of $4.1 million (i.e. a reduction of $65.9 million from the actual surplus of $70.0 million. In EGI’s view, this result clearly demonstrated that EGI’s success in reducing the actual FMORs of these units from forecast was the primary cause of EGI’s actual surplus above forecast in the higher priced environment of the year 2000. The Board notes that the PROSYM model uses a random draw to determine the hourly distribution of forced plus maintenance (F+M) outages. Accordingly, the original 2000 PROSYM runs would have determined a profile for the forecast F+M outages based on the original random draws. The Board notes that the EGI simulation would determine a different profile for the forecast F+M outages based on new random draws. The EGI simulation would also determine a profile for actual F+M outages based on a random draw. This profile would be different from the actual profile for F+M outages. The Board is concerned that these random draws may introduce distortions into the simulations such that the simulation would not be persuasive evidence upon which the Board could rely to

8 IPCCAA Argument page 20 9 EGI Reply page 9




determine an appropriate sharing of the deferral account. Further, EGI combined the effect of forced and planned outages in the simulation. The Board does not believe that the change to planned outages should be regarded as a performance improvement. Accordingly, the Board considers that the forced and planned outages should be dealt with separately. Apart from the inclusion of planned outages in the PROSYM simulation and the way the model created the forecast F+M outage profiles, the Board is concerned that it may not be fully aware of all assumptions that EGI used, which might have affected the output of the model. This is further reason why the Board is not inclined to use EGI’s PROSYM simulations as the basis for assessing whether the deferral account formula should be changed and, if so, how it should be changed. The Board notes that the surplus/shortfall recorded in the deferral account is really a composite of the following four components:

1. Increased surplus during times of unit operation as a result of the unit being called upon to run more often due to higher pool price absent any improved performance statistics.

2. Increased surplus during times of unit operation as a result of the unit being called upon and available to run more often due to improved performance statistics.

3. Avoided shortfall during times when the unit is down (i.e. shortfall would be increased absent performance improvements).

4. Avoided shortfall as result of planned outages deferred from year 2000 to year 2001. Components 2 and 3 shown above represent the components of the deferral account that, in the Board’s view, are a result of improved availability or increased performance. In the Board’s view, in determining the effect of increased availability, it is important to also consider when the unit is available. Viewing the surplus/shortfall as a composite of the above components brings this issue into focus. In other words, given the same annual outage rate (i.e. FMOR), EGI would achieve a higher surplus if EGI were able to shift the outages to periods of low pool price than if the outages occurred during periods of high pool price. In the spreadsheet developed by the Board in Appendix 2, the Board has calculated the increased surplus and the avoided shortfall components of the surplus. The remaining surplus was viewed as being related to the unit being called upon to run more often due to higher pool price absent any improved performance statistics. In the Board’s view, the increased surplus and avoided shortfall resulting from improved availability (i.e. increased performance) should not be regarded as an unintended windfall to EGI. However, the remaining increased surplus resulting from the unit being called upon to run more often simply due to higher pool price and absent any improved availability should be classed as an unexpected and unintended windfall. Further, the avoided shortfall as a result of planned outages deferred from the year 2000 to year




2001 should also be classed as unexpected and unintended provided EGI is kept whole respecting any additional costs incurred in the year 2001. The following table summarizes the results of some sensitivity runs, using the Appendix 2 model, to provide an estimate of the appropriate sharing percentages using different outage frequencies as a percent of peak hours (i.e. on-peak and off-peak margins). These results exclude hedging losses and the Rossdale error correction. Table 6: Corrected Board Approved - Sharing Resulting from Peak Hour Outage Frequency

Outage Frequency of Peak Hours (%)

EGI Shareholder $ Millions (%)

Customers $ Millions (%)

0 5.6 (8 %) 64.7 (92 %) 10 7.1 (10 %) 63.2 (90 %) 20 8.7 (12 %) 61.7 (88 %) 30 10.2 (14 %) 60.2 (86 %)

40* 11.7 (17 %) 58.6 (83 %) 50 13.3 (19 %) 57.1 (81 %)

* 40% is equal to the percentage of the hours defined as peak hours/total hours in the year. In the Board’s view, if the outages occurred randomly without any operator influence, they would tend to be spread evenly over all hours of operation and the appropriate sharing would be based on an outage frequency of 40% within peak hours. However, the Board notes EGI’s evidence in the 1999/2000 GTA proceedings that “plant operators have some flexibility to delay unplanned forced maintenance outages into weekends.”10 The Board considers that, given the tight supply situation during the year 2000, it is reasonable to expect that EGI would move some of the unplanned forced maintenance occurring during peak hours to non-peak hours. The effect of these delays would be a reduction to the 40% assumption. The Board considers that EGI’s motivation to delay unplanned forced outages to non-peak hours would be stronger in a high pool price environment since EGI would have the opportunity to create higher value for its shareholders. Based on these considerations, the Board is of the view that an outage frequency of 40% during peak hours would be generous to EGI and would provide a greater share of the surplus to EGI’s shareholder than EGI has perhaps earned. However, given that EGI did not provide the magnitude of the amount of outages that occurred in peak hours compared to off-peak hours, the Board must make an estimate of the outage that occurred in peak hours. Based on EGI’s evidence, it is clear to the Board that the percentage would likely be less than a straight 40% occurrence of outages in peak hours.

10 Decision U99099, page 61




Accordingly, the Board concludes that it will utilize an outage frequency within peak hours of 30% for purposes of this Decision as a reasonable estimate for evaluation of this factor alone.11 In light of this determination, the Board considers that the Appendix 2 spreadsheet provides a reasonable test according to which the Board can decide the extent to which a revised sharing of the EGI gas unit deferral account is warranted in the circumstances. In Appendix 2 (page 1 of 4), the Board has concluded that, based on a 30% on-peak factor, EGI should be entitled to $8.53 million of the deferral account for the unplanned FMOR portion of improved availability. This amount includes the avoided shortfalls, other than avoided shortfalls from deferral of planned outages, but is prior to any considerations of additional costs incurred due to a delay of planned outages from the year 2000 to the year 2001. Therefore, in the next sub section, the Board will consider whether EGI incurred additional costs due to a delay of planned outages from the year 2000 to the year 2001. Following that consideration, the Board will make a final determination with respect to sharing the EGI gas units deferral account in the summary sub-section below. (Click here for Quick Hyperlink to return to start of Board Views regarding EGI Gas Units Sharing.) 4.2.3 Views of the Board - Additional EGI Costs – Delay of Planned Outages The Board notes that EGI did not identify any additional 2001 costs that it incurred with respect to the reduction in planned outages for the Rossdale units. However, EGI did identify additional costs with respect to delaying the planned outages of the Clover Bar 1 and 2 units from 2000 to 2001. The Board must consider whether and to what extent EGI should be compensated for those additional costs in the context of its gas units deferral account. The Board agrees with IPCCAA that there were “strong financial incentives for EGI to take actions, take calculated risks and incur costs” in the rescheduling of the Clover Bar 1 and 2 turnarounds from 2000 to 2001. The Board will, therefore, consider these costs when finally determining the appropriate sharing formula for EGI’s gas units deferral account. The Board will now determine the appropriate level of compensation to EGI for deferring the Clover Bar turnarounds from the year 2000 to the year 2001. The Board notes that EGI calculated the additional cost in 2001 to be about $8 million in total for the gas units, based on outages of 23 days at each unit. The Board agrees with IPCCAA, however, that EGI’s $8 million estimate appears to be high, considering that the normal outage for these units, based on the planned 2000 outages, would be 12 days each. The Board considers that the forecast maintenance costs were incorporated in

11 The Board recognizes that in this determination, the Board might still be erring on the generous side to EGI shareholders, thereby providing EGI with a higher benefit from the deferral account than might be justified in other circumstances.




the year-2000 costs allowed by Decision U99099 and no evidence was provided by EGI that the simple deferral of these outages increased these costs. EGI also did not demonstrate to the Board’s satisfaction why the turnaround increased to 23 days from the planned 12 days as a result of the deferral of the turnaround to 2001. The Board notes that IPCCAA’s calculation of the additional cost of deferring these outages to 2001, based on a 12-day outage, was approximately $1.67 million.12 The Board notes that the method used by IPCCAA to calculate the volume associated with a 12-day outage was referred to, by EGI,13 as the type of “general calculation” that could be used to estimate generation loss. The Board accepts IPCCAA’s calculation as being appropriate for the purposes of this section of the Decision. Accordingly, the Board has incorporated the $1.67 million in the results shown in Table 6 above. As noted in a later section, the Board has also accounted for the avoided shortfall respecting the deferral of the Clover Bar 1 and 2 planned maintenance to year 2001. The Board recognizes that, based on the evidence on the record, it is difficult to precisely calculate these impacts. Accordingly, in making it final determination with respect to sharing the EGI gas units deferral account, the Board will round the sharing percentage in EGI’s favor. The Board will make a final determination with respect to sharing the EGI gas units deferral account in the summary sharing sub-section below. (Click here for Quick Hyperlink to return to start of Board Views regarding EGI Gas Units Sharing.) 4.3 Corrected Summary - Board Approved Sharing of Gas Units Deferral Account In Appendix 2, the Board has calculated the appropriate sharing of the deferral account that should be awarded to EGI for improved performance with respect to both planned and unplanned outages to be 14% or $10.2 million dollars. This share represents an estimate of the increased surplus net of the costs associated with increased availability. The Board notes that, absent any variation of the sharing formula, EGI would have received a benefit of $35 million dollars. Accordingly, without a variation to the 50/50 sharing formula, the Board considers a reasonable estimate of the net windfall to EGI to be $24.8 million (i.e. $35 million less $10.2 million). For all of the foregoing reasons, the Board concludes that, taking into account those components of the deferral account surplus that can be reasonably be attributed to EGI’s improved performance (net of EGI’s reasonable costs), the 50/50 sharing formula approved by the Board in Decision 2000-5 would leave EGI with a net “windfall” of some $24.8 million. The Board considers such a significant windfall not to have been contemplated when the sharing formula was established and further considers that allowing EGI to retain this net windfall would not be just and reasonable to customers.

12 IPCCAA noted that the spread between the Clover Bar running cost (gas at $7/GJ) and Pool Price is $20-$30/MWh x 2 units X 145 MW/unit X 12 days X 24 hours/day X $20/MWh = $1.67 million.

13 Transcript page 1937




Accordingly, the Board concludes that it is appropriate to vary the deferral account sharing formula to eliminate this unintended windfall that would accrue to EGI under a “50% Customers/50% EGI” sharing. The Board is satisfied that the 50/50 sharing, if applied to the entire surplus, will lead to an unjust and unreasonable result by virtue of the substantial and unforeseen change in circumstances which gave rise to the large surplus. To that extent, the Board is accordingly satisfied that the criteria of section 57(2)(c) of the EU Act are satisfied. Given the calculations shown on Appendix 2 page 4 of 4, and all other things being equal, the Board would have considered that a “86% Customers/14% EGI” sharing would be fair, would appropriately award EGI for improved performance, and would maintain regulatory consistency. Using the calculations in Appendix 2 (page 4 of 4) would result in a reduction in the EGI share from EGI’s applied-for $35 million to a revised share for EGI of $10.2 million. The customer share would accordingly increase from $35 million to $60.2 million. Again, all other things being equal, the Board considers that this sharing would appropriately reward EGI for the component due to improved performance and would return to customers the component due to units being called on more often due to higher than forecast pool prices. Although Appendix 2 demonstrates a reasonable determination of the appropriate financial sharing of EGI’s gas units deferral account, as discussed in the foregoing sections, the Board is also mindful of other factors, such as those listed below, that are difficult to quantify.

• The actual outage percentage in peak hours. • The actual financial impact of deferring the Clover Bar turnarounds from 2000 to 2001. • The variability of results associated with hourly pool prices and variable gas prices

associated with gas units operating on the margin. In the Board’s view, these factors, though difficult to quantify, tend to suggest that a slightly higher percentage share would be more reasonable for EGI, notwithstanding the calculations in Appendix 2. Erring on the generous side of providing a further benefit to EGI, the Board considers that an 80% Customers/20% EGI sharing would lead to a just and reasonable sharing of EGI’s gas unit deferral account. Accordingly, the Board concludes that the 50/50 sharing formula approved in Decision 2000-5 for EGI’s gas units deferral account should be varied and approves a sharing formula of 80% Customers/20% EGI. The Board’s approval of this variation, prior to any adjustment for hedging and the Rossdale refiling error, confers on EGI a share amount of $14.1 million compared to the $10.2 million using a 14 % sharing as shown on Appendix 2. This variation confers on customers a share amount of $56.3 million compared to the $60.2 million as shown on Appendix 2. The comparisons between EGI’s applied-for amounts, the Board’s Appendix 2 tests amounts and the Board approved amounts are set out in the table below.




Table 7: Corrected Board Approved Sharing of EGI Gas Units Deferral Account

EGI Proposed Sharing

($ Million)

Board Test Appendix 2 Sharing

Calculations ($ Million)

Board Approved Appendix 2 Sharing

($ Million) EGI Share 35.0 10.2 14.1 Customer Share 35.0 60.2 56.3 (Click here for Quick Hyperlink to return to start of Board Views regarding EGI Gas Units Sharing.) Accordingly, the Board directs EGI, in its refiling, to incorporate the “80% Customers/20% EGI” sharing of the deferral account for the EGI gas units. 5 CORRECTION TO APPENDIX 2 OF DECISION 2001-95

The Board has also attached an amended Appendix 2 which corresponds with the correct version of Sections 4.2.2 and 4.3 as set out above. 6 AMENDED SUMMARY OF APPROVALS AND CONCLUSIONS

The Board also notes that the correct version of Sections 4.2 and 4.3 also require amendment to Conclusions 2 and 3 listed in the Summary of Approvals and Conclusions Conclusion Number 2 (Decision 2001-95 page 33) currently reads as follows:

In Appendix 2 (page 1 of 4), the Board has concluded that, based on a 30% on-peak factor, EGI should be entitled to $10.78 million of the deferral account for the unplanned FMOR portion of improved availability. This amount includes the avoided shortfalls, but is prior to any considerations of additional costs incurred due to a delay of planned outages from the year 2000 to the year 2001.

Conclusion Number 3 (Decision 2001-95 page 36) currently reads as follows:

Accordingly, the Board concludes that the 50/50 sharing formula approved in Decision 2000-5 for EGI’s gas units deferral account should be varied and approves a sharing formula of 80% Customers/20% EGI. The Board’s approval of this variation, prior to any adjustment for hedging and the Rossdale refiling error, confers on EGI a share amount of $14.1 million compared to the $12.5 million using a 18% sharing as shown on Appendix 2. This variation confers on customers a share amount of $56.3 million compared to the $57.9 million as shown on Appendix 2.

As set out in the corrected version of Section 4.2.2 and 4.3 above, the Board hereby amends




Conclusion Number 2 of Decision 2001-95 to read as follows:

In Appendix 2 (page 1 of 4), the Board has concluded that, based on a 30% on-peak factor, EGI should be entitled to $8.53 million of the deferral account for the unplanned FMOR portion of improved availability. This amount includes the avoided shortfalls, other than avoided shortfalls from deferral of planned outages, but is prior to any considerations of additional costs incurred due to a delay of planned outages from the year 2000 to the year 2001.

As set out in the corrected version of Section 4.2.2 and 4.3 above, the Board hereby amends Conclusion Number 3 of Decision 2001-95 to read as follows:

Accordingly, the Board concludes that the 50/50 sharing formula approved in Decision 2000-5 for EGI’s gas units deferral account should be varied and approves a sharing formula of 80% Customers/20% EGI. The Board’s approval of this variation, prior to any adjustment for hedging and the Rossdale refiling error, confers on EGI a share amount of $14.1 million compared to the $10.2 million using a 14% sharing as shown on Appendix 2. This variation confers on customers a share amount of $56.3 million compared to the $60.2 million as shown on Appendix 2.

Dated in Calgary, Alberta on December 27, 2001 ALBERTA ENERGY AND UTILITIES BOARD <original signed by> N. W. MacDonald, P. Eng. Presiding Member <Mr. Berg agrees with this Decision, but was unavailable for signature> A. J. Berg, P. Eng. Member <original signed by> R. G. Lock, P. Eng. Member




7 APPENDIX 2 - EGI GAS UNITS DEFERRAL ACCOUNT SHARING PER BOARD

"Appendix 2 EGI GasUnits Deferral Accoun


PART N: AMENDMENT OF DECISION 2001-95 RESPECTING THE TIMING OF EGI GENCO PAYMENT 2000 Pool Price Deferral Accounts Proceeding

EPCOR Generation Inc. Appendix 22000 Deferral Account Application

Month Actual PP UOP Actual Margin

Forecast PP

UOP ForecastMargin

Actual PP

UOP Actual Margin

Forecast PP

UOP ForecastMargin

Jan $61.59 $32.86 $28.73 $41.27 $32.86 $8.41 $37.69 $32.86 $4.83 $32.88 $32.86 $0.02 Feb $51.41 $35.97 $15.45 $36.38 $31.25 $5.13 $44.49 $35.97 $8.53 $24.86 $31.25 ($6.39)Mar $111.32 $40.91 $70.41 $40.23 $29.30 $10.94 $54.26 $40.91 $13.35 $26.48 $29.30 ($2.82)Apr $142.09 $43.79 $98.31 $24.64 $27.11 ($2.47) $68.35 $43.79 $24.57 $16.83 $27.11 ($10.28)May $67.63 $50.92 $16.72 $28.24 $26.65 $1.59 $41.69 $50.92 ($9.23) $15.48 $26.65 ($11.17)Jun $181.40 $64.76 $116.64 $41.15 $29.54 $11.61 $57.52 $64.76 ($7.24) $21.12 $29.54 ($8.42)Jul $217.60 $57.42 $160.18 $33.17 $29.66 $3.52 $69.93 $57.42 $12.51 $22.69 $29.66 ($6.97)Aug $339.94 $60.96 $278.98 $34.85 $29.89 $4.97 $116.02 $60.96 $55.06 $21.51 $29.89 ($8.38)Sep $285.56 $80.27 $205.29 $44.91 $30.00 $14.91 $114.51 $80.27 $34.24 $25.21 $30.00 ($4.79)Oct $344.95 $81.78 $263.17 $35.55 $30.58 $4.97 $200.26 $81.78 $118.48 $25.44 $30.58 ($5.14)Nov $343.58 $91.36 $252.22 $36.35 $33.11 $3.25 $151.38 $91.36 $60.02 $24.35 $33.11 ($8.76)Dec $250.01 $143.85 $106.16 $40.23 $35.41 $4.83 $158.55 $143.85 $14.70 $28.34 $35.41 ($7.07)

Average $199.76 $65.40 $134.35 $36.41 $30.44 $5.97 $92.89 $65.40 $27.48 $23.77 $30.44 ($6.68)

Forecast Outage (GWh) 373Actual Outage (GWh) 56Availablity Improvement (GWh) 317UOA Portion (Note 1) 261Surplus Portion (Note 2) 26Undispatched portion 30On peak factor (Note 3) 0.30

Increase Surplus ($ millions)(Note 4) $2Avoided Shortfall($ millions)(Note 5) $16

Increased Surplus resulting from increased availability ($millions) $17EGI Share @ 50% 8.5

Note 1: UOA portion equals 692 MW UOA divided by 841 MCR for EGI Gas Units times increased availabilityNote 2: Surplus portion equals MCR minus UOA times ratio of dispatch %- UOA % divided by MCR%-UOA%Note 3: On peak factor equals 40% (on peak hours divided by total hours) Note 4: The Board has calculated the increased surplus using on-peak and off-peak availability improvements times relevant on-peak and off-peak actual margins Note 5: The Board has calculated the avoided shortfall using on-peak and off-peak availability improvements times relevant on-peak and off-peak actual margins

Increased Surplus arising from Availability Improvement for EGI Gas Units

On-Peak Off-Peak

EUB Decision 2001-115 (December 27, 2001) Page 1 of 4

PART N: AMENDMENT OF DECISION 2001-95 RESPECTING THE TIMING OF EGI GENCO PAYMENT2000 Pool Price Deferral Accounts Proceeding


11.5 11.5Month Gas

[email protected] GJ/MWh

O&M STS Total UOP

Gas Price [email protected] GJ/MWh

O&M STS Total UOP

Jan $2.84 $32.66 $0.20 $32.86 $2.84 $32.66 $0.20 $32.86Feb $3.11 $35.77 $0.20 $35.97 $2.70 $31.05 $0.20 $31.25Mar $3.54 $40.71 $0.20 $40.91 $2.53 $29.10 $0.20 $29.30Apr $3.79 $43.59 $0.20 $43.79 $2.34 $26.91 $0.20 $27.11May $4.41 $50.72 $0.20 $50.92 $2.30 $26.45 $0.20 $26.65Jun $5.05 $58.08 $0.20 $6.49 $64.76 $2.30 $26.45 $0.20 $2.89 $29.54Jul $4.44 $51.06 $0.20 $6.16 $57.42 $2.31 $26.57 $0.20 $2.89 $29.66Aug $4.60 $52.90 $0.20 $7.86 $60.96 $2.33 $26.80 $0.20 $2.89 $29.89Sep $6.34 $72.91 $0.20 $7.16 $80.27 $2.34 $26.91 $0.20 $2.89 $30.00Oct $6.44 $74.06 $0.20 $7.52 $81.78 $2.39 $27.49 $0.20 $2.89 $30.58Nov $7.27 $83.61 $0.20 $7.56 $91.36 $2.61 $30.02 $0.20 $2.89 $33.11Dec $11.93 $137.20 $0.20 $6.45 $143.85 $2.81 $32.32 $0.20 $2.89 $35.41

Actual and Forecast UOPs for EGI Gas Units

Actual UOP Forecast UOP




MCR Max Gen In merit Forecast Forecast Actual Actual Inc Offered Dispatch DispatchGen FMOR Outage FMOR Outage Availiblity GWh GWh %

A B=Ax8784 C=Ax6595 D E=CxD F G=CxF H=E-G I=C-G J KHours 8784 6595Clover Bar 1 158 1388 1042 3.34% 35 1.49% 16 1026 914 89%Clover Bar 2 158 1388 1042 1.98% 21 0.95% 10 1032 923 89%Clover Bar 3 158 1388 1042 26.14% 272 0.83% 9 1033 927 90%Clover Bar 4 158 1388 1042 2.12% 22 1.09% 11 1031 936 91%Sub total 14335 4168 350 45 304 4123 3700 90%

A B=Ax8784 C=Ax4068 D E=CxD F G=CxF H=E-G I=C-G J KHours 8784 4068Rossdale 8 67 589 273 4.27% 12 0.67% 2 271 260 96%Rossdale 9 71 624 289 3.06% 9 1.06% 3 286 259 91%Rossdale 10 71 624 289 0.78% 2 1.86% 5 283 266 94%Sub Total 1836 850 23 10 12 840 785 93%

Total 16171 5018 373 56 317 4963 4485 90%




Response to Information Request BR-EGI-03Clover Bar and Rossdale Surplus (Shortfall) Calculation - 2000 - Summary($millions)

PER EGI PER Board

A B C D E EGI Cust TotalShare Share

Notes Cloverbar Rossdale Total

1 Pool receipts 588.725$ 144.864$ 733.589$ 2 Variable Ancillary Services Revenues 49.185 26.523 75.708 3 Unit Obligation Values (345.350) (102.416) (447.766) 4 Variable Fuel and O&M (222.990) (57.491) (280.481)

Sub total 81.050 81.050 5 Supply Transmission Service (16.661) (4.232) (20.893) (20.893) 6 Pool Price Hedging Activity (1) (0.551) - (0.551) -

7 Actual Plant Surplus (Shortfall) 52.358 7.248 59.606 60.157

8 GTA Re-filing Surplus (Shortfall)9 Per Re-filing (8.117) (2.175) (10.292) (10.292) 10 Correction (2) - 0.100 0.100 0.100

11 Revised (8.117) (2.075) (10.192) (10.192)

12 Excess of Actual over GTA Forecast 60.475$ 9.323$ 69.798$ $8.528 61.821$ 70.34970.349

13 Cust share 30.238$ 4.662$ 34.899$ 61.821$ 14 Impact on Rossdale Error on 2000 ARP (2) - 0.100 0.100 0.100

Clover Bar Adjustment $1.670 (1.670)

15 Total Calculated Refund to Customers 30.238$ 4.762$ 34.999$ $10.198 60.151$ 70.34950% 14% 86%

Board Approved Sharing 14.070 56.27920% 80%

Notes: 70.35 Impact on Rossdale Error on 2000 ARP (2) 0.100Cust Share 56.37950 % Share of Hedging Cost -0.276Total Customer Share 56.104Increase in Cust share 21.105

(1) See EGI 2000 Deferral Account Application, Section 2.2.5

(2) See EGI 2000 Deferral Account Application, Section 2.2.4


Decision 2001-115: 2000 Pool Price Deferral Accounts …€¦ · amend Directions Numbers 6 and 7...

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