EPCOR Energy Alberta Inc. - AUC · 2018. 2. 23. · ALBERTA UTILITIES COMMISSION Decision 2010-571:...

Decision 2010-571

EPCOR Energy Alberta Inc. 2010-2011 Regulated Rate Tariff Non-Energy Charge December 16, 2010

ALBERTA UTILITIES COMMISSION Decision 2010-571: EPCOR Energy Alberta Inc. 2010-2011 Regulated Rate Tariff Non-Energy Charge Application No. 1605758 Proceeding ID. 436 December 16, 2010 Published by Alberta Utilities Commission Fifth Avenue Place, 4th Floor, 425 - 1 Street SW Calgary, Alberta T2P 3L8 Telephone: (403) 592-8845 Fax: (403) 592-4406 Web site: www.auc.ab.ca

http://www.auc.ab.ca/

Contents

1 INTRODUCTION AND BACKGROUND ......................................................................... 3

2 NEGOTIATED SETTLEMENT AGREEMENT APPLICATION ................................. 4

3 COMMISSION FINDINGS ON THE SETTLEMENT AGREEMENT ......................... 5 3.1 Commission Considerations in Assessing the Settlement Agreement ........................... 5 3.2 Fairness of Negotiated Settlement Process .................................................................... 7 3.3 Just and Reasonable Rates and Public Interest Considerations ..................................... 8

3.3.1 Individual Components of the Settlement Agreement ...................................... 8 3.3.2 Return ................................................................................................................ 9 3.3.3 Bill Impacts ..................................................................................................... 10 3.3.4 Terms and Conditions ..................................................................................... 11 3.3.5 Refiling Process leading to Determination of Final Rates .............................. 12 3.3.6 Items EEAI to address in next RRT Application ............................................ 13 3.3.7 Conclusion on Individual Components of the Settlement Agreement ............ 13

3.4 The Settlement Agreement as a Whole ........................................................................ 14

4 NO-COST CAPITAL ADJUSTMENT ............................................................................. 14 4.1 Need for an Adjustment and Public Interest Factors ................................................... 14 4.2 Beginning Date ............................................................................................................ 16 4.3 Inclusion of Income Tax Related to Energy Sales ....................................................... 16 4.4 Yearly No-Cost Capital Amounts ................................................................................ 17

4.4.1 Taxes Paid Versus Taxes Collected Method .................................................. 17 4.4.2 Draw Down of No-Cost Capital ..................................................................... 18 4.4.3 Use of Actual Earnings and Adjustments for Changes in Tax Rates ............. 19

5 COMMON MATTERS ...................................................................................................... 19 5.1 Corporate Services ....................................................................................................... 20 5.2 Station Lands Project ................................................................................................... 21 5.3 Forecast Assumptions .................................................................................................. 21

5.3.1 Compensation and Labour Escalation ............................................................ 21 5.3.2 Short Term and Long Term Incentive Programs ............................................ 22 5.3.3 Contractors, Other and Material Escalation .................................................... 24

5.4 International Financial Reporting Standards (IFRS) ................................................... 24

6 ORDER ................................................................................................................................ 25

APPENDIX 1 – PROCEEDING PARTICIPANTS ................................................................. 26

APPENDIX 2 – NEGOTIATED SETTLEMENT AGREEMENT ........................................ 27

AUC Decision 2010-571 (December 16, 2010) • i

AUC Decision 2010-571 (December 16, 2010) • 3

ALBERTA UTILITIES COMMISSION Calgary Alberta EPCOR ENERGY ALBERTA INC. Decision 2010-571 2010-2011 REGULATED RATE TARIFF Application No. 1605758 NON-ENERGY CHARGE Proceeding ID. 436

1 INTRODUCTION AND BACKGROUND

1. EPCOR Energy Alberta Inc. (EEAI) filed its 2010-2011 non-energy regulated rate tariff application (Application) with the Alberta Utilities Commission (AUC or Commission) on December 22, 2009.

2. The Application requested: a. approval of the proposed monthly non-energy charges applicable to eligible

customers in EPCOR Distribution & Transmission Inc. (EDTI) and FortisAlberta Inc. (Fortis) service areas;

b. approval of the proposed price schedules which included Miscellaneous Fees;

c. approval of Regulated Rate Tariff (RRT) Terms and Conditions; and

d. approval for continued use of the Bad Debt Expense Deferral Account, the Hearing Cost Reserve, and the Regulatory Capital Projects Deferral Account.

3. The Commission electronically issued a Notice of Application on December 23, 2009 which required that interested parties submit a Statement of Intent to Participate (SIP) by January 18, 2010. Notice was also published in four major Alberta newspapers (Edmonton Journal, Edmonton Sun, Calgary Herald, and Calgary Sun) on January 4, 2010. SIPs were received from the Consumers’ Coalition of Alberta (CCA), the Office of the Utilities Consumer Advocate (UCA), and ENMAX Energy Corporation.

4. In a letter dated February 2, 2010, the Commission established the process and schedule for the proceeding, which included an interrogatory process. In accordance with the process schedule, on March 23, 2010, EEAI submitted its responses to Information Requests (IRs). Incorporated into these IR responses were amendments or updates to the original Application for certain elements, including the requested non-energy return margin. The Commission established an additional round of IRs to facilitate examination of the amended Application information.

5. By letter dated April 22, 2010, EEAI requested Commission approval to initiate a negotiated settlement process (NSP) with the registered intervener groups with respect to the Application. EEAI proposed negotiation of all matters, except for the areas defined as Common Matters, identified as being common between the Application and EDTI’s 2010-2011 General Tariff Application (GTA).1 The Commission requested comments from interested parties on the proposed NSP, whether the parties intended to be active in the negotiations, and regarding EEAI’s proposed composition and handling of the Common Matters through the EDTI GTA.

1 EDTI GTA Proceeding ID. 437.

2010-2011 RRT Non-Energy Charge EPCOR Energy Alberta Inc.

4 • AUC Decision 2010-571 (December 16, 2010)

6. Following receipt and review of comments received from parties, which confirmed that the CCA and the UCA would be active in the proposed negotiations; the Commission requested and received further information which confirmed that interested parties had reached agreement on the specific topics that would be addressed through the Common Matters proposal.

7. In a letter dated May 27, 2010, the Commission approved EEAI’s request to negotiate matters with registered intervener groups related to the Application with the exception of the Common Matters, which would be addressed in the EDTI GTA proceeding. The Commission established a timeline for the remainder of the proceeding to assist with scheduling, which included an end date for negotiations.

8. By letter dated May 28, 2010, the Commission approved EEAI’s proposal to address the Common Matters in the EDTI GTA proceeding, and confirmed the specific topics that were included within the Common Matters.

9. In accordance with the process schedule, on July 26, 2010 EEAI provided a negotiation status update and informed the Commission that a settlement had been reached. In response, on August 16, 2010, the Commission cancelled the scheduled oral hearing. On August 23, 2010, EEAI filed a fully-executed, unanimous and partial negotiated settlement agreement (Settlement Agreement) with the Commission. On September 3 and 27, 2010 respectively, the Commission issued information requests requesting additional information to assist with its review of the Settlement Agreement.

10. In a letter dated September 27, 2010, the Commission established a written process and schedule, which included an interrogatory process, to address the outstanding issue regarding a potential adjustment for no-cost capital related to EEAI’s use of the Future Income Tax method.

11. On October 29, 2010, reply argument was received from the parties related to the outstanding issue from the Settlement Agreement. For purposes of this Decision, the Commission considers that the record closed on October 29, 2010.

2 NEGOTIATED SETTLEMENT AGREEMENT APPLICATION

12. The Settlement Agreement was developed by the parties2 and executed effective August 23, 2010. The Appendices to the Settlement Agreement are summarized as follows:

• Appendix A – Agreed to Deferral Accounts for the 2010 to 2011 Test Period. • Appendix B – Regulatory Schedules reflecting the adjustments to EEAI’s 2010-2011 Forecast

amounts set out in the 2010-2011 Application. 13. In the Negotiated Settlement Application (Settlement Application), EEAI requested that the Commission explicitly approve specific matters reflected in the Settlement Agreement and the Application insofar as the Commission is of the view that such approval is necessary to allow for their implementation. Such matters included, without limitation:

2 Signatories to the Settlement Agreement included EPCOR Energy Alberta Inc., and the Office of the Utilities

Consumer Advocate and the Consumers’ Coalition of Alberta (collectively the Customer Intervener Group or CIG) , as set out on page 1 of the agreement.



(a) The agreed upon revenue requirement for the years 2010 and 2011, as described in the Settlement Agreement.

(b) The deferral accounts as described in Section 4 and Appendix A of the Settlement Agreement.

(c) EEAI’s Terms and Conditions and Fee Schedule, as identified and described in Section 8 of the 2010-2011 Application.

(d) The written proceeding requested by the parties to determine whether there should be an adjustment for no-cost capital as a result of EEAI’s use of the Future Income Tax method.

(e) A limited reopener for 2010 through 2011 where in the event that at any time during the years 2010 and 2011, EEAI experiences a gain or loss of RRT or other site counts in the cumulative amount of 250,000 sites (net of forecast attritions and growth forecast in EEAI’s 2010-2011 Application), as described in Section 6 of the Settlement Agreement.

(f) Adjustments for Common Matters and International Financial Reporting Standards (IFRS) following which the current interim RRT rates will be made final in accordance with EEAI’s filing resulting from the Commission’s decision in Proceeding ID 437 (Application No. 1605759), as described in Section 12 of the Settlement Agreement.

14. EEAI submitted that the Settlement Agreement was just and reasonable and in the public interest, both on a component-by-component basis and on an overall basis, and should be approved by the Commission.

3 COMMISSION FINDINGS ON THE SETTLEMENT AGREEMENT

3.1 Commission Considerations in Assessing the Settlement Agreement 15. EEAI sought approval of the Settlement Agreement pursuant to section 135 and Division 3 of Part 9 of the Electric Utilities Act, and AUC Rule 001 – Rules of Practice, and AUC Rule 018 – Rules on Negotiated Settlements. The Settlement Agreement was negotiated on the basis that it must be accepted or rejected in its entirety by the Commission.3 Accordingly, pursuant to Section 135 of the Electric Utilities Act, the Commission must either approve the entire settlement or reject it.

16. Section 132(1) of the Electric Utilities Act directs the Commission, inter alia, to recognize or establish rules, practices and procedures that facilitate the negotiated settlement of matters arising under the Electric Utilities Act or the regulations.

17. Rule 018 establishes several requirements that must be met by an applicant seeking approval of a settlement agreement. These requirements include the following:

• Section 3(1) requires parties to the settlement agreement to include a statement in the settlement agreement confirming that proper notice was provided by the applicant to all interested parties.

• Section 6(3) requires the applicant to provide material to allow the Commission to assess the impact to rates and services, including:

o the rates that result or will result from the settlement, supported by schedules, to assist the Commission in understanding how the rates were derived;

o the text of any changes to the terms and conditions of service with supporting information; and

3 Settlement Agreement, Section 19.



o unless the Commission directs otherwise, a settlement brief explaining the basis of the settlement and how it meets the interests of the parties and the public interest.

• Section 6(5) places the onus on the applicant to ensure that there is sufficient evidence to support the application, including the settlement agreement, and that the quality and detail of the evidence and the rationale for the settlement of issues are sufficient to enable the Commission to understand and assess the agreement.

18. Rule 018 also establishes the manner in which the Commission must assess a settlement agreement. As no objections were received with respect to the Settlement Agreement in the current proceeding,4 the Commission will assess the Settlement Agreement before it on the basis of the requirements set out in Section 8 of Rule 018, which specifically addresses unanimous or unopposed settlements.

19. Section 8 of Rule 018 requires that the Commission assess the Settlement Agreement on the basis of two elements:

1. whether the Settlement Agreement will result in rates and terms and conditions that are just and reasonable; and

2. whether the Settlement Agreement is patently against the public interest or contrary to law.

20. In considering these elements with respect to the Settlement Agreement, the Commission has taken into account the direction of the Alberta Court of Appeal as set out in ATCO Electric Limited v. Alberta (Energy and Utilities Board), 2004 ABCA 215 (ATCO Electric Decision). In accordance with findings of the Court in that decision, the Commission considers that the responsibility for approving negotiated settlements – and ensuring that the process operates in a fair and reasonable manner – rests with the Commission.5

21. In assessing negotiated settlements, the Commission is aware that while one or more of the interested parties to a settlement may represent some consumers, none will represent all. Further, as noted by the Court at paragraph 138 of the ATCO Electric Decision, “even a broad range of [i]ntervenors will not necessarily translate into a wide spectrum of positions since parties may make trade-offs which leave other issues unresolved, unaddressed or compromised.” Consequently, the negotiated settlement process does not replace an appropriate and informed review by the Commission as to what is in the overall public interest.6 As EEAI had requested and received Commission approval to negotiate a settlement with its customers, subsequently negotiated and executed the Settlement Agreement, and then applied to the Commission for approval of the Settlement Application in its entirety, in accordance with the ATCO Electric Decision, the Commission will proceed on the basis that the Settlement Agreement satisfies the interests of EEAI, and will only assess the Settlement Agreement from the point of view of the consuming public.7

4 Representatives of the UCA and the CCA (CIG) were all in agreement with the Settlement Agreement, including

all constituent parts, as evidenced by the completed signatory pages at the end of the Settlement Agreement. 5 ATCO Electric Decision, paragraph 138. 6 ATCO Electric Decision, paragraph 139. 7 ATCO Electric Decision, paragraphs 145 and 146.



22. The Commission has considered all of the following matters, taken together, in making its determination as to whether the Settlement Agreement should be accepted or rejected in its entirety:

• If the process resulting in the Settlement Agreement was fair. In this regard the Commission considered whether there was procedural fairness, both with respect to adequate notice having been served and with respect to the conduct of the negotiation process itself.

• If approval of the Settlement Agreement will lead to rates and terms and conditions that are just and reasonable. In this regard, the Commission notes that the Settlement Agreement sets out proposed revenue requirements for the years 2010 and 2011. The Commission has considered the reasonableness of the revenue requirements in the Settlement Agreement, in their entirety, relative to the revenue requirements requested in the Application. The Commission has also considered the reasonableness of the individual elements that make up the revenue requirements to the extent they have been set out in the Settlement Agreement. In addition, the Commission has considered the expected impact of the revenue requirements and related matters in the Settlement Agreement on forecast non-energy charges.

• Whether the Settlement Agreement is patently contrary to the public interest or contrary to law. The Commission has reviewed each of the material provisions of the Settlement Agreement in order to determine if any of these material provisions, individually, appear contrary to accepted regulatory practices, or could result in undue rate and service impacts to customers. The Commission’s findings on specific provisions of the Settlement Agreement are discussed in further detail in the following sections of this Decision.

3.2 Fairness of Negotiated Settlement Process 23. EEAI indicated that the Settlement Agreement represented a comprehensive settlement of all issues arising from the Application except for the written proceeding requested by the parties to determine whether there should be an adjustment for no-cost capital as a result of EEAI’s use of the Future Income Tax method,8 and the adjustments for Common Matters/IFRS.9 EEAI stated:10

(a) The Application, supporting material, responses to information requests and all information filed with the AUC contains all material information and facts relied upon by EEAI to support its RRT revenue requirements for the 2010-2011 test years;

(b) To the knowledge of EEAI, the information provided by it in its filings with the AUC and during the negotiation of this Agreement and up to the date of this Agreement does not contain any untrue statement of fact; and

(c) At this time, EEAI has no plans or intentions and is not aware of any plans or intentions that would have, or potentially have, a material effect on its RRT revenue requirements for the 2010 and 2011 test years.

24. A Commission appointed observer was present during the negotiation sessions. The Commission Observer advised the Commission that the negotiation process was open and fair to all interested parties and that it was conducted on a confidential and without prejudice basis and accommodated the parties’ unique circumstances and requirements. 8 Settlement Agreement, Section 12 (a). 9 Settlement Agreement, Section 12 (b). 10 Settlement Application, Section 13 (a) (b) (c).



25. EEAI indicated that there were no issues with respect to the Application that have been left unresolved or are otherwise outstanding except for the written proceeding requested by the parties to determine whether there should be an adjustment for no-cost capital as a result of EEAI’s use of the Future Income Tax method, and the adjustments for Common Matters/IFRS. All issues have been dealt with unanimously, and no party disagrees with any aspect of the settlement.

26. As noted above, the first question for the Commission to consider is whether the EEAI settlement process was fair. In this regard, the Commission has considered the following factors:

• No party objected to EEAI’s request to negotiate in response to the Commission’s letter asking for comments. The UCA and the CCA filed comments and each indicated that they intended to be active participants in the proposed settlement negotiations.

• While ENMAX Energy Corporation had originally registered for the proceeding, it did not participate in the settlement process, nor was it an active participant in either the proceeding or the negotiations.

• In letters dated May 27and 28, 2010 respectively, the Commission approved EEAI’s request to negotiate and the process to address Common Matters.

• Notice of the negotiation settlement process was provided by EEAI to all interested parties, as required under Section 3(1) of AUC Rule 018.11

• The parties to the Settlement Agreement confirmed that proper notice was provided with respect to the negotiation process.12

• The NSA was unanimous and unopposed.

• No party to the negotiations objected to the settlement process or stated that it was unfair.

• A Commission Observer was in attendance during the negotiation sessions.

• The Commission Observer has, in accordance with Section 5(2) of Rule 018, advised the Commission as to the fairness of the negotiated settlement process.

27. The Commission has reviewed the entire evidentiary record,13 and is satisfied that it forms a full and complete information package which would allow all parties to fully understand both the terms of and reasoning used in reaching the Settlement Agreement. Also the attendance of the Commission Observer provides a level of assurance that interested parties had the opportunity to participate, and participants were afforded due process.

28. Accordingly, the Commission finds that the EEAI settlement process was fair.

3.3 Just and Reasonable Rates and Public Interest Considerations

3.3.1 Individual Components of the Settlement Agreement

29. The Commission recognizes that the Settlement Agreement resulted from a successful negotiation reflecting a number of compromises of different interests and positions. The multiple stakeholder groups participating in the settlement process, which included the UCA and

11 Settlement Application, Appendix 1. 12 Settlement Agreement, Section 21(l). 13 The record consists of all filed documents including the Application, multiple rounds of information responses,

and the materials filed regarding the Settlement Application and Common Matters.



the CCA, and the fact that the Settlement Agreement was unanimous and unopposed, support a finding that the Settlement Agreement is in the public interest.

30. The Settlement Agreement forecast revenue requirements for EEAI’s non-energy Regulated Rate Tariff for 2010 and 2011 respectively are $42.71 million and $44.64 million. These revenue requirement amounts reflect negotiated adjustments to identified cost areas. A limited reopener related to changes in site counts is included as well as agreement on the continued use of three existing deferral accounts.

31. EEAI requested approval of a number of specific items in the Settlement Agreement. The Commission examined each of the material provisions of the Settlement Agreement and, in the sections of the Decision that follow, has made specific findings based on the Commission’s review to determine whether the provisions are just and reasonable and in the public interest.

3.3.2 Return 32. The Settlement Agreement revenue requirement includes a non-energy return margin based on 6 percent of EEAI’s non-energy RRT operating costs, plus applicable income taxes for each of the test years. In addition, the parties included a debt return on the total of: the equity portion of EEAI’s rate base allocated to RRT, corporate rate base allocated to RRT and working capital allocated to RRT, to which the debt return rate of 6 percent was applied, but without the inclusion of income taxes which were not applicable.14

33. EEAI submitted that the combined return included in the Settlement Agreement reflected parity between RRT providers based on the global return received by ENMAX Energy Corporation (ENMAX) for its non-energy RRT service.15 EEAI stated that because Direct Energy Regulated Service’s return was stated as a single value that included both non-energy and energy, it was not possible to determine whether it received a debt return on 100 percent of its rate base, including working capital.16

34. EEAI confirmed that the parties had considered the debt return on equity to be a cost recovery of EEAI’s interest carrying costs on the portion of EEAI’s rate base previously assumed to be financed by equity which was akin to the interest carrying costs on property, awarded to ENMAX in Decision 2006-001.17 EEAI highlighted that similar treatment had been included in ENMAX’s recent 2009-2011 RRO Non-Energy Application.18

35. The Commission has reviewed the return information available on the record of this proceeding and considers that the debt return on equity agreed upon by the parties is reasonable and that it supports consistent treatment of return between RRT providers where comparable information is available, namely a comparison with ENMAX. The Commission finds that the

14 Settlement Agreement, Section 5(i) and (j); and Appendix B, Schedules 1.1 and 1.5. 15 Information Response AUC-EEAI-30. 16 Ibid. 17 Decision 2006-001: ENMAX Energy Corporation 2005 Regulated Rate Tariff Non-Energy (Application No.

1380523) (Released: January 13, 2006), Information Response AUC-EEAI-31. 18 Proceeding ID. 521, submitted March 1, 2010.

http://www.auc.ab.ca/applications/decisions/Decisions/2006/2006-001.pdf



non-energy return margin has been reflected in the Settlement Agreement in a manner consistent with the determinations in Decision 2010-055.19

36. The Commission finds the negotiated return as reflected in the Settlement Agreement to be reasonable and in the public interest, as it results in consistency between RRT service providers.

3.3.3 Bill Impacts 37. The table below provides a comparison of the forecast monthly non-energy charges per site per month that would be applicable to eligible customers in the EDTI and Fortis service areas based on the Settlement Agreement.

Table 1. Estimated Non-Energy Monthly Charge Impact of the 2010-2011 Settlement Agreement Rates vs. Interim Rates20

38. On an average basis across all the rate classes shown in the table above, the non-energy monthly charge based on 2009 actual amounts was $5.37, and with the Settlement Agreement the average charge for 2010 and 2011 would increase to $6.01 and $6.42.21 The resulting average year over year non-energy charge increases were approximately 12 percent and 7 percent. EEAI indicated22 that in 2010 approximately 50 percent of the increase related to return items, which also included the additional return approved in Decision 2010-055, with the remainder for 2010 and all of the increase in 2011 related to other non-return items such as inflation for labour and other costs. EEAI stated that increases in forecast Corporate Service costs and increased cost allocations to RRT sites due to the decline in non-RRT site counts also contributed to the increases to other non-return items.

19 Decision 2010-055 – EPCOR Energy Alberta Inc. Review Hearing on Alberta Energy and Utilities Board

Decision 2008-031, 2007-2009 Regulated Rate Tariff Non-Energy Return (Application 1577836, Proceeding ID. 174) (Released: February 8, 2010).

20 Application, Appendix B – Bill Comparison Schedules. 21 Information Response AUC-EEAI-33, Table AUC-EEAI-33-1, row 36 ($ per site per month). 22 Information Response AUC-EEAI-33(c), Table AUC-EEAI-33-2.

2010 2010 2011 2010 2011 Customer Type Interim Settlement Settlement % Impact % Impact Fortis Service Area Residential $ 5.51 $ 5.97 $ 6.40 8.3% 7.2% Farm $ 5.10 $ 5.70 $ 6.15 11.8% 7.9% Irrigation $ 5.59 $ 5.46 $ 5.88 -2.3% 7.7% Small Commercial $ 5.23 $ 6.49 $ 6.95 24.1% 7.1% Oil Gas $ 3.79 $ 5.06 $ 5.54 33.5% 9.5% Lighting $ 5.68 $ 5.46 $ 5.99 -3.9% 9.7%

EDTI Service Area Residential $ 5.65 $ 6.08 $ 6.45 7.6% 6.1% Small Commercial $ 5.08 $ 5.81 $ 6.22 14.4% 7.1% Lighting $ 5.45 $5.68 $ 6.09 4.2% 7.2%




39. In response to a Commission request for additional information on the Settlement Agreement impacts by customer class, EEAI provided a breakdown of the increases shown in Table 1 above by the different contributing cost categories.23 These tables demonstrate that the difference between the increase amounts by customer class is based on a number of contributing cost categories, some which apply equally to all classes and some to a narrow group for such items as bad debt and late payment charges.

40. The Commission has reviewed the bill impact information and the contributing cost categories. The Commission considers that parties that represent the majority of the customer classes impacted by these increases, shown in Table 1 above, were signatories to the Settlement Agreement and have therefore accepted these increases, and that all parties had the opportunity to register and participate in the proceeding. The Commission notes overall increases based on the Settlement Agreement of $6.01 and $6.42 respectively for 2010 and 2011 are lower than EEAI’s Application which had originally requested $7.12 and $7.5924 respectively for 2010 and 2011.

41. The Commission does not find the proposed increases to the monthly non-energy charges which result from the Settlement Agreement to be unjust or unreasonable for 2010 and 2011, given the acceptance of these by the parties representing the majority of the customer classes and the even higher increases proposed in the Application.

3.3.4 Terms and Conditions 42. EEAI’s Terms and Conditions and Fee Schedules were approved on a final basis effective August 1, 2008, in Decision 2008-06325 in the context of EEAI’s 2007-2009 RRT Refiling Application. EEAI’s existing Terms and Conditions and Fee Schedules were approved on an interim basis effective January 1, 2010, in Decision 2009-255.26

43. Updated Terms and Conditions and Fee Schedules were included in the Application and reflect operational and clarification changes, summarized by EEAI in the Settlement Application,27 and also the addition of a customer notification fee.

44. The Commission has reviewed the changes to the Terms and Conditions and Fee Schedules which form part of the Settlement Agreement.28 The Commission considers that the operational and clarification changes will be of assistance to parties, and finds that overall the changes are reasonable.

23 Bill Impacts-C, and Tables AUC-EEAI-39-1and AUC-EEAI-39-2. 24 Information Response AUC-EEAI-33, Table AUC-EEAI-33-1, row 36 ($ per site per month). 25 Decision 2008-063 – EPCOR Energy Alberta Inc. 2007-2009 Regulated Rate Tariff Non-Energy Charge Refiling

(Application 1573623) (Released: July 23, 2008). 26 Decision 2009-255 – EPCOR Energy Alberta Inc. 2010 Interim Regulated Rate Tariff (Application 1605584,

Proceeding ID. 359) (Released: December 14, 2009). 27 Settlement Application, Section 4.3, page 12, paragraph 31. 28 Settlement Agreement, Section 3.





3.3.5 Refiling Process leading to Determination of Final Rates 45. The Settlement Agreement included the following Section29 related to determining final rates for 2010 and 2011:

(a) The 2010 and 2011 non-energy revenue requirements, including the adjustments set out in section 5 above, shall be subject to adjustment in the Compliance Filing for certain Common Matters that are determined in the Commission’s Decision in Proceeding ID. 437 (Application 1605759) dealing with the Distribution Tariff Application of EDTI, as set out in the AUC’s letter dated May 28, 2010 regarding Common Matters Scope and Process (the “Common Matters”). (b) In addition to the Common Matters, EEAI will adopt the Commission’s decision in Proceeding ID. 437 (Application 1605759) dealing with the Distribution Tariff Application of EDTI with respect to the IFRS treatment of indirect capital overhead for the year 2011. (c) As soon as the AUC makes its final determination on the Common Matters and IFRS treatment of indirect capital overheads in Proceeding ID. 437 (Application 1605759) dealing with the Distribution Tariff Application of EDTI, EEAI shall, in accordance with the time period set by the AUC, file the required 2010 and 2011 RRT rate adjustments with the AUC for implementation of final rates. (d) It is agreed the current interim RRT rates will remain interim and refundable pending approval of the 2010 and 2011 RRT rates as adjusted for the Common Matters and IFRS treatment of indirect capital overheads following the AUC’s decision in Proceeding ID. 437 (Application 1605759) dealing with the Distribution Tariff Application of EDTI.

46. In a letter dated February 2, 2010, the Commission had contemplated that final RRT non-energy rates might be determined for the proceeding through the use of a single Compliance Filing which would include the Settlement Agreement components related to the Common Matters, IFRS treatment of indirect overheads, and any other adjustments arising from Commission determinations.

47. Section 5 of this Decision summarizes the Common Matters and IFRS findings from Decision 2010-50530 with respect to the adjustments necessary to determine final rates for 2010 and 2011. For reasons that will be further explained in Section 5, EEAI’s corporate costs as filed in the Application and included in the Settlement Agreement can not be finalized until the completion of the separately convened Corporate Cost Module for the EDTI 2010-2011 GTA proceeding.

48. As indicated above, 2010 interim RRT rates have been in effect since January 1, 2010. Decision 2009-255 approved 2010 Interim RRT Non-energy Charges as were reflected in the price schedules, along with Interim Terms and Conditions, and the 2010 Interim Bad Debt Expense Deferral Account with bad debt percentages by customer class.

49. Given that the non-energy RRT revenue requirement for 2010 and 2011 cannot be finalized until the completion of the Corporate Cost Module, the Commission directs that the current 2010 interim RRT rates should be updated or amended through the Compliance Filing that will be required following this Decision. Use of updated rates as early as possible in 2011

29 Settlement Agreement, Section 12 (a) through (d). 30 Decision 2010-505 – EPCOR Distribution & Transmission Inc. 2010-2011 Phase I Distribution Taiff; 2010-2011

Transmission Facility Owner Tariff (Application 1605759, Proceeding ID. 437) (Released: October 28, 2010).




will serve to reduce the difference between final and interim rates that will have otherwise accumulated to be collected in future periods in addition to the difference resulting from 2010.

50. Based on the timing of the Compliance Filing related to this Decision as specified in the Order section and the resulting approval and implementation of amended interim RRT non-energy rates, EEAI is directed to propose a method that can be used to recover/refund the differences between the interim and final rates for 2010 and 2011.

51. The Commission directs EEAI to revise its forecast 2010-2011 RRT revenue requirement, proposed amended interim rates, proposed fees, and proposed Terms and Conditions in accordance with the directions set out in this Decision, to also include corrections for errors and omissions as identified on the record of the proceeding, and to submit a Compliance Filing with these items to the Commission no later than January 10, 2011.

3.3.6 Items EEAI to address in next RRT Application 52. In accordance with Sections 5(g), 8, 9 and 10 of the Settlement Agreement,31 EEAI shall address the following items in conjunction with and for purposes of its next RRT Application:

(1) Capital Additions in the Operating Expenses forecast shall not be adjusted; provided that EEAI shall develop business cases for projects with a capital cost greater than $250,000 for EEAI’s next Non-Energy GTA;

(2) EEAI will adopt a mid-year in service date for all forecast staff additions created within EEAI for the purposes of its next GTA;

(3) A portion of EEAI’s incentive compensation payments will be capitalized for the purposes of EEAI’s next GTA, consistent with its capitalization policy; and

(4) EEAI will include leads (lags) associated with interest expense and income tax payments in the working capital calculation for the purpose of EEAI’s next GTA. Additionally, EEAI will review and update the components of the working capital calculation and make adjustments where warranted for the purposes of EEAI’s next GTA.

53. As part of the package deal reflected in the Settlement Agreement, the parties have agreed that it is reasonable for EEAI to address these matters as part of its next RRT Application where parties will have an opportunity to review the results of EEAI’s work in these areas.

54. The Commission considers it to be reasonable that EEAI shall address the above Settlement Agreement matters in EEAI’s next RRT Application. However, the Commission considers that none of these items restricts the Commission in exercising its discretion respecting any aspect of EEAI’s next RRT Application.

3.3.7 Conclusion on Individual Components of the Settlement Agreement 55. As a result of its analysis in this Decision of the material components of the Settlement Agreement, the Commission has found no reason to conclude that the treatment of these components would result in undue rate increases or unreasonable service impacts to customers or customer classes, or that the Settlement Agreement could be considered to be, from the perspective of the consuming public, patently against the public interest or contrary to law as it is reflected in accepted regulatory principles or practices.

31 Settlement Agreement, Sections 5(g), 8, 9 and 10.



3.4 The Settlement Agreement as a Whole 56. In addition to reviewing the material components of the Settlement Agreement, the Commission considered whether, taken as a whole, the proposed rates and terms and conditions are just and reasonable. In this regard, the Commission considers that the rates reflect the 2010 and 2011 revenue requirement and that the RRT cost allocation methodologies used by EEAI are reasonable. In considering the Settlement Agreement as a whole, the Commission has again found no reason to conclude that the settlement would result in undue rate increases or unreasonable service impacts to customers or customer classes, or that the Settlement Agreement could be considered to be, from the perspective of the consuming public, patently against the public interest or contrary to law as it is reflected in accepted regulatory principles or practices.

57. The Commission therefore approves the Settlement Agreement.

4 NO-COST CAPITAL ADJUSTMENT

58. Parties to the Settlement Agreement could not agree to an adjustment for no-cost capital (NCC) in respect of EEAI’s collection of income taxes under the Future Income Tax method. The Commission established a written process and schedule to address this remaining issue from the Negotiated Settlement Process.

59. The Commission has considered the submission from EEAI, and the joint submission from the UCA and the CCA (who referred to themselves collectively as the Consumer Intervener Group).

4.1 Need for an Adjustment and Public Interest Factors 60. EEAI questioned the need for any adjustment to its revenue requirement related to no-cost capital.

EEAI is not convinced that the public interest favours an adjustment for NCC, and certainly not a significant adjustment which reaches far back in time, introduces a new layer of regulatory complexity and imposes significant ongoing adjustments.32

61. In support of this, EEAI discussed the non-monopoly nature of RRT service, the possible impact an adjustment might have on fair and open competition, the lack of any adjustment in Decision 2006-055, the introduction of uncertainty and the after-the-fact nature of the adjustment.33

62. EEAI noted that:

In Decision 2006-055, the EUB remarked that:

The Board also notes that for regulatory purposes, any amounts paid by customers in respect of future income tax liabilities are considered to be no-cost capital.34

32 EEAI Argument, paragraph 10. 33 EEAI Argument, Section 3.0. 34 EEAI Argument, paragraph 14.




63. EEAI submitted that:

If the EUB had considered an adjustment in respect of no-cost capital to be appropriate and necessary for EEAI, a clear and express adjustment would have to have been made in Decision 2006-055. Instead, the EUB simply noted that amounts paid by customers in respect of future income tax liabilities are considered to be no-cost capital and made no mention of any adjustment.35

64. EEAI submitted that making an adjustment to the revenue requirement for no-cost capital introduces unneeded uncertainty not contemplated by the RRO Regulation or Section 103 of the Electric Utilities Act.36

65. The UCA/CCA submitted that the issue at hand was not to determine whether or not an adjustment was necessary but rather the issue was to determine the quantum of the adjustment.37

The UCA/CCA submitted that EEAI’s questioning of whether there was a need for any adjustment was at odds with EEAI’s October 6, 2010 submission38 which proposed an adjustment, and with EEAI’s responses to information requests that included supporting calculations and even an alternative adjustment amount.

Commission Findings

66. The Commission observes that, as referenced above, in Decision 2006-055 the EUB noted that future income taxes were considered to be no-cost capital. The Commission also notes that Decision 2006-055 directed EEAI to use the future income tax method in its next GTA.39

67. In EEAI’s refiling which was directed in Decision 2006-055, EEAI categorized the direction regarding the use of future income tax as a directive to be dealt with in its next GTA.

68. The Commission notes EEAI’s current position that Decision 2006-055 did not consider an adjustment in respect of no-cost capital to be appropriate and necessary for EEAI since a clear and express adjustment was, in EEAI’s view, not made in Decision 2006-055. EEAI argued that the decision instead simply noted that amounts paid by customers in respect of future income tax liabilities were considered to be no-cost capital and made no mention of any adjustment. The Commission considers this position to be without merit. In 2005 and 2006, EEAI’s non-energy return was calculated using a traditional return on rate base approach rather than a margin approach. Under the traditional approach to rate base return, no-cost capital reduced the invested capital on which a return was awarded. Further, the evidence indicates that Decision 2006-055 directed future income taxes to be accounted for in the next GTA which would explain why no adjustment was made for 2005-2006. The Settlement Agreement includes a non-energy return margin, plus a debt return on the equity portion of rate base as discussed in Section 3.3.2 of this Decision. The Commission considers that the inclusion of no-cost capital would result mainly in an adjustment to this debt return component.

35 EEAI Argument, paragraph 15. 36 EEAI Argument, paragraph 16. 37 UCA/CCA Reply Argument, paragraph 8. 38 EEAI NCC Submission, Exhibit No. 124. 39 Decision 2006-055, page 40.



69. The Commission agrees with the UCA/CCA that EEAI appears to have taken a revised position in its Argument on the need for an adjustment, a position which is at odds with its October 6, 2010 submission.

70. For the above reasons, the Commission directs EEAI to reflect no-cost capital related to its use of the Future Income Tax method as part of its capital structure used to determine the revenue requirement for the test years in the Application, and to continue this methodology for future rate applications.

4.2 Beginning Date 71. In its October 6, 2010 submission EEAI submitted that in accordance with the above referenced finding in Decision 2006-055, its calculation of no-cost capital balances begins with the year 2005.

72. The UCA/CCA submitted that the calculation of no-cost capital should begin in 2001, the first year that EEAI was in operation as a regulated RRT provider.

73. EEAI responded that the UCA/CCA’s proposal to begin the calculation in year 2001 amounted to retrospective ratemaking and amounts to confiscation of amounts previously approved.

Commission Findings

74. The Commission notes that Decision 2006-055 was silent on the date at which a no-cost capital calculation would begin. Decision 2006-055 directed that the future income tax method be applied for the next GTA after the 2005/2006 period but did not indicate whether or not no-cost capital would be calculated for 2005/2006 or prior years. Considering these circumstances, the Commission finds that EEAI’s proposal to begin the calculation with year 2005 is fair and reasonable. The Commission considers that the UCA/CCA’s position requiring EEAI to calculate no-cost capital back to 2001 would be unfair and administratively inefficient.

4.3 Inclusion of Income Tax Related to Energy Sales 75. In its submission of October 6, 2010, EEAI noted that its calculation of no-cost capital included estimates of income tax related to RRT energy as well as to non-energy.

76. The UCA/CCA argued that income tax related to energy amounts should be excluded from EEAI’s no-cost capital calculations. The UCA/CCA submitted that the effect of including the income tax related to the energy amounts increased income taxes payable resulting in a significant reduction in the no-cost capital adjustment related to the non-energy RRT revenue requirement. The UCA/CCA submitted that the no-cost capital issue arose in regard to the non-energy component and that the energy and non-energy operations are treated, for rate making purposes, akin to stand-alone entities.40

77. EEAI responded that it is a single company and that Decision 2006-055 did not indicate that future income taxes should be calculated separately for energy versus non-energy.

40 UCA/ CCA Argument, Section 4, pages 11 through 13.



Commission Findings

78. The Commission notes that energy and non-energy rates for EEAI’s RRT business have historically been determined for regulatory purposes through separate regulatory proceedings which have focused on the energy and non-energy components separately.

79. Although Table 2.0-1 of EEAI’s October 6, 2010 submission41 does not individually identify income taxes related to its energy charge after 2006, the table adds an energy pretax margin, which in effect includes the amount that would be paid for the corresponding income taxes. In response to the UCA/CCA concern that the no-cost capital balance is negatively impacted by the inclusion of the energy pretax margin, the Commission agrees that the result of EEAI’s calculation as shown is that income tax payable is higher than if it had only been based on the non-energy income tax related amounts. This higher income tax payable results in a lower no-cost capital balance, to the detriment of customers.

80. The Commission notes that EEAI’s table shows that no income tax was collected on the RRT energy charge amount shown in years after 2006, but that income tax was collected in 2005 and 2006. There is no information on the proceeding record as to why that was the case. In the Commission’s view, to the extent that EEAI is collecting a negotiated margin on its energy sales that does not specifically identify an adder for income taxes after 2006 in the above referenced table, it would be reasonable to assume that given that an energy pretax margin is included, negotiation of that energy margin had considered income taxes.

81. The Commission considers it to be proper matching for the current proceeding to determine non-energy revenue requirement using a no-cost capital calculation which is only based on non-energy income tax related amounts. Therefore, the Commission finds that income tax related amounts for energy should not be included in the calculation of no-cost capital that is used to determine non-energy charges.

82. The Commission directs EEAI to provide detailed calculations of its no-cost capital balance for all applicable years, as part of its refiling, including the calculation of no-cost capital adjustments to be reflected in the revenue requirement for the test years.

4.4 Yearly No-Cost Capital Amounts

4.4.1 Taxes Paid Versus Taxes Collected Method 83. The UCA/CCA submitted that future income tax amounts should be calculated in reference to EEAI’s actual tax filings and that this was consistent with the method that was used by ATCO Electric Ltd. (ATCO Electric). In its October 6, 2010 submission, the UCA/CCA had described the method used by ATCO Electric.

84. EEAI submitted that the Commission should reject the application of the ATCO Electric no-cost capital precedent to the circumstances of EEAI because the regulatory approach for a distribution utility was not warranted as EEAI was a RRT provider under different legislative and regulatory frameworks.42

41 EEAI NCC Submission, Exhibit No.124. 42 UCA/CCA Argument, paragraph 28.



Commission Findings

85. Based on the evidence provided, the Commission is not able to confirm that ATCO Electric’s calculation of future income taxes makes use of actual income tax filings, nor is there enough information on this record to determine the precise methods used by ATCO Electric. The Commission notes that the UCA/CCA’s position that actual income tax filings, which are filed on a corporate entity basis, should be used is at odds with the UCA/CCA’s position, as discussed in Section 4.3 of this Decision, that the energy and non-energy components of EEAI should be treated separately because they have historically been determined for regulatory purposes through separate regulatory proceedings which have each focused on the energy or non-energy components. EEAI does not file a separate income tax return for its energy vs. non-energy activities; instead the actual income tax filing is on a corporate entity basis that includes one or more lines of business, some of which would be non-regulated. For purposes of using actual income tax filings for calculating future income taxes, the Commission considers that Section 4.4.3 of this Decision effectively already addresses this point because actual non-energy earnings and the actual tax rates will be used to recalculate future income taxes for the test years and on a going forward basis.

4.4.2 Draw Down of No-Cost Capital 86. The UCA/CCA recommended that EEAI be directed to draw-down the no-cost capital balances to defray the income tax payable on the RRT non-energy return margin. They submitted that given the availability of future tax balances in the test years, and the draw-down of these balances, there should be no component of income taxes in the test year revenue requirements.43

87. EEAI submitted:

EEAI’s understanding of NCC is that it reflects cash available from sources other than debt or equity that can fund either cash operating expenses for regulated entities earning a return margin or a return on rate base. The Consumer Advocates supply no authority for the proposition that NCC should be used to reduce income taxes collectible under the FIT method. Using NCC to reduce income taxes is akin to the flow-through method of accounting for income taxes. The Consumer Advocates are mixing up the two distinct methods for accounting for income taxes.44

Commission Findings

88. The Commission’s understanding is that under the Future Income Tax method the amount of income collected based on the statutory tax rate is often higher than the cash income taxes payable. This is primarily due to quicker “write-offs” of fixed assets for income tax purposes, as opposed to accounting purposes. Any cash income tax that is collected but not paid is considered to be used to invest in rate base and that same amount, the future income tax balance, is treated as no-cost capital and recognized as a liability because it is an amount expected to be paid in future although it is not yet legally owed to the taxation authorities.

43 UCA/CCA Argument, paragraph 40. 44 EEAI Reply Argument, paragraph 44.



89. If the timing difference eventually reverses, which can be expected to happen if rate base is stagnant or shrinking, then “cross-over” occurs whereby the cash income taxes paid are greater than the income tax collected. In this situation the future income tax “liability” begins to decrease over time.

90. The Commission agrees with EEAI that the UCA/CCA’s proposal mixes two distinct methods of collecting and accounting for income tax. In the Commission’s view if cross-over is imminent such that cash income taxes payable start to exceed the statutory income tax rate, it makes no sense whatsoever to cease collecting income taxes. The no-cost capital amounts or future income tax will reduce or be “drawn down” in due course while EEAI remains on the Future Income Tax method.

91. For the above reasons, the UCA/CCA’s proposal to draw-down the no-cost capital balances to defray the income tax payable on the RRT non-energy return margin is rejected.

4.4.3 Use of Actual Earnings and Adjustments for Changes in Tax Rates 92. The UCA/CCA submitted that, consistent with the well-established practice of the Commission, no-cost capital balances should be calculated based on actual earnings and actual income tax rates rather than estimated or forecast amounts.45

93. EDTI responded that such an adjustment would be minimal amounting to a revenue reduction of $1,200 per year in respect of the use of actual earnings and a further $1,800 reduction per year in respect of the use of updated income tax rates.

Commission Findings

94. The Commission notes that EEAI did not argue that the UCA/CCA’s position on this matter was wrong, but rather that the amounts were essentially too small to be addressed. The Commission notes that based on its findings above EEAI will have to re-calculate its non-energy no-cost capital and the related revenue impact to eliminate the inclusion of taxes paid on the energy-related portion of its earnings. Given that a re-calculation is required, EEAI is directed to include the use of actual earnings and the actual tax rates in its recalculation.

5 COMMON MATTERS

95. As noted above, in a letter dated April 22, 2010 EEAI requested that the Commission allow EEAI to initiate an NSP in respect of all matters related to its Application, except for the areas it defined as Common Matters. EEAI identified the Common Matters as those matters common between the Application and EDTI’s 2010 -2011 GTA. EEAI proposed that determinations on Common Matters should be made in the EDTI GTA proceeding and then apply to the RRT proceeding.46

96. On May 19, 2010 EEAI submitted the following list of Common Matters jointly proposed by EEAI and interested parties intervening in the RRT proceeding:

45 UCA/CCA Argument, paragraphs 22 and 23. 46 EPCOR Common Matters Submission, Exhibit 93.02.



Table 2. Detailed List of Proposed Common Matters Topics EUI Organizational Structure and Reorganization Corporate Services • Direct Assigned Corporate Costs • Allocated Corporate Costs – 2007-2009 • Allocated Corporate Costs – 2010-2011 • Changes to Corporate Cost Allocation Methodology • Non-Recoverable Corporate Costs • Corporate Asset Usage Fees • PA Consulting Report • Removal of Generation Business from Corporate Allocations • Depreciation on Corporate Assets

Station Lands Project • Business Case • Basis for Determination of Costs Allocated or Directly Assigned to EDTI/EEAI

Forecast Assumptions • Compensation and Labour Escalation • Contractors, Other and Materials Escalation • Calculation of STI • Calculation of LTI • Common Forecast Assumptions - General • Common Assumptions – Fringe

97. By letter dated May 28, 2010 the Commission stated that it considered that including the Common Matters within the EDTI GTA proceeding promoted efficiency by minimizing duplication of process and associated costs and, as such, approved EEAI’s proposal for addressing the Common Matters in the EDTI GTA proceeding.

98. On October 28, 2010, the Commission released Decision 2010-505 in respect of EDTI’s 2010-2011 GTA. Included in that Decision was a discussion of relevant issues that were addressed by parties related to the Common Matters along with the Commission’s findings with respect to those Common Matters. What follows is a summary of what was proposed by EDTI/EEAI in the various Common Matters sections of their respective applications, the corresponding Commission findings from Decision 2010-505 and the Commission findings with respect to EEAI and the RRT Application. The Commission’s rationale in support of the findings in respect of EDTI can be found in the relevant sections of Decision 2010-505.

5.1 Corporate Services 99. The corporate costs allocated from EPCOR Utilities Inc. (EUI) to EDTI/EEAI were discussed in Section 4.3 of Decision 2010-505. In that section the Commission concluded that it was not in a position to determine the proper regulatory treatment of EDTI’s and EEAI’s allocated corporate costs, considering the effects of the corporate restructuring following the spin-off of Capital Power Corporation (Capital Power) from EUI. The Commission directed that a separate module be convened in order to further investigate the corporate costs in a more detailed fashion. The Commission approved EDTI/EEAI’s applied for corporate costs on an interim and refundable basis. The Commission stated that after the completion of the separate corporate costs module, a final determination on the corporate costs matter would be made and consolidated with EDTI’s and EEAI’s revenue requirements.



Commission Findings

100. Accordingly, EEAI’s corporate costs as filed in the Application are approved on an interim refundable basis with final approval to be issued once the separate corporate costs module has been completed.

5.2 Station Lands Project 101. The Station Lands Building project was discussed at length in Section 4.2.1 of Decision 2010-505. Station Lands is a new building currently under construction in downtown Edmonton. EUI and EEAI will both occupy the building in addition to Capital Power. A long term lease has been signed with 20 year fixed lease rates. The lease cost per square foot is substantially higher than the lease costs in the space that EUI currently occupies. The annualized Station Lands building cost to EEAI starting in 2012 will be approximately $3.6 million consisting of $2.0 million embedded in corporate cost allocations and $1.6 million in direct space rent costs.47

102. At paragraph 34 of Decision 2010-505 the Commission noted that during the 2010-2011 test period the costs associated with the Station Lands building included in revenue requirement are relatively small as occupancy is not forecast to occur until November 2011.

103. EEAI provided a business case comparing the net present value of the status quo alternative, with all EPCOR employees continuing to occupy space in more than one building in downtown Edmonton, and the Station Lands alternative. That business case showed the net present value for the Station Lands alternative to be $24 million, or 25 percent, more expensive than the status quo alternative over the 20 year period.

Commission Findings

104. In Decision 2010-505 the Commission found that EDTI had not made the case that the Station Lands Building alternative justified the forecast increase in costs of 25 percent. Accordingly, the Commission directed EDTI to reflect this 25 percent premium by including only 80 percent of the lease costs of the Station Lands Building in its revenue requirement until the expiry or renegotiation of its current 20 year lease.

105. Similarly, for the purpose of this Decision, the Commission directs EEAI to include only 80 percent of the lease costs of the Station Lands Building in its revenue requirement until the expiry or renegotiation of its current 20 year lease.

5.3 Forecast Assumptions

5.3.1 Compensation and Labour Escalation

106. The Commission addressed the labour escalation rates utilized by EDTI in Section 5.4 of Decision 2010-505.

107. EDTI/EEAI compensates employees differently depending on whether they are unionized or non-unionized. EDTI/EEAI compensates unionized employees through base compensation (hourly wages /annual salaries); employer paid benefits and short term incentive.48 Non-

47 Decision 2010-505, paragraphs 33 and 35. 48 Application, page 95, paragraph 283.



unionized employees are compensated in the same manner but there is also a long term incentive plan for participating Directors, Vice Presidents and Executives.

108. In their respective applications, EDTI/EEAI escalated the base salaries of all of its non-unionized employees by 3.5 percent for both 2010 and 2011.49

109. For Civic Service Union (CSU) employees, EDTI/EEAI applied an escalation rate of 5.25 percent to CSU base salaries for 2010. This rate reflects the rate agreed to in the last year of a four year collective bargaining agreement. EDTI/EEAI both utilized an escalation rate of 3.3 percent for CSU employees in 2011.

Commission Findings

110. In Decision 2010-505 the Commission approved the 5.25 percent escalation rate for CSU employees for 2010. The Commission found that the agreement was negotiated in good faith and that EDTI had provided this increase to its CSU employees for 2010 on the basis of its contractual obligation. The Commission also noted that the escalation factor of 5.25 percent for CSU employees for 2010 was the last year of a four year collective bargaining agreement. However, the Commission did not approve an escalation factor of 3.3 percent for CSU employees for 2011 based on the fact that EDTI’s unionized employees are paid 9 percent over market. For CSU employees for 2011 the Commission directed EDTI to apply an escalation factor of 2 percent.

111. The Commission approved the escalation factors that EDTI applied to the base salaries of its non-unionized employees as submitted in the Application and summarized above.

112. The Commission directed EDTI to file separate market competitiveness studies for EDTI, EEAI and EUI at the time of its next rate application.

113. The Commission has reviewed the labour escalation findings from Decision 2010-505 noted above and considers them to be equally applicable to EEAI. Accordingly the Commission approves an escalation factor of 3.5 percent for EEAI’s non-unionized employees for both 2010 and 2011. The Commission approves an escalation factor of 5.25 percent for EEAI’s CSU employees for 2010. However, the Commission does not approve an escalation factor of 3.3 percent for 2011 and directs EEAI to utilize a 2.0 percent escalation factor for its CSU employees for 2011. The Commission makes this finding for EEAI given the fact that EDTI/EEAI proposed the same escalation rate for 2011, being 3.3 percent, for its CSU employees. The Commission also directs EEAI to file separate market competitiveness studies for EDTI, EEAI and EUI at the time of its next rate application. The Commission expects that the separate market competitiveness studies will provide increased clarity in respect of the separate breakdown of salaries within EEAI and EDTI.

5.3.2 Short Term and Long Term Incentive Programs 114. The Commission addressed EDTI’s short term and long term incentive programs in Section 5.4 of Decision 2010-505.

49 Application, page 105, paragraph 320.



115. EDTI/EEAI did not include any amounts related to its long term incentive program in revenue requirement in the Application.50

116. There are three components to EDTI/EEAI’s short term incentive program: an EUI net earnings component weighted at 40 percent, an EDTI/EEAI activity measure weighted at 30 percent and an individual employee performance measure weighted at 30 percent. EDTI/EEAI said, consistent with previous Commission directions, it excluded 50 percent of the costs associated with the earnings component of its short term incentive program from its revenue requirement.51

Commission Findings

117. In Decision 2010-505 the Commission directed EDTI to establish a deferral account to capture any approved short term incentive amounts in revenue requirement that are not actually paid out, with these unpaid amounts to be returned to the benefit of customers.

118. The Commission noted that the earnings component of short term incentive programs of other utilities in Alberta have typically been limited to a 10 percent weighting. The Commission found that a 10 percent earnings component of a short term incentive plan appropriately balances incentives for the utility to be more efficient, which benefits consumers in the long run, while at the same time recognizing that the utility benefits from increased net earnings in the shorter term. The Commission made this finding notwithstanding that a higher portion of net earnings was approved for EEAI’s short term incentive plan in Decision 2008-031.52

119. The Commission considered that it would be unfair to change the performance measures for EDTI’s and EEAI’s short term incentive plan for 2010 because EDTI’s employees and EEAI’s employees have been working to achieve those performance measures throughout 2010 and the year is almost over.

120. The Commission directed EDTI to reduce the weighting of the earnings component of its short term incentive program from 20 percent to 10 percent for 2011. The Commission directed EDTI to increase the activity measure and the individual employee performance measure by 5 percent each. The Commission also approved the total cost of EDTI’s short term incentive program for 2010 and 2011 as filed.

121. The Commission has reviewed the findings respecting EDTI’s short term and long term incentive programs from Decision 2010-505 noted above and considers them to be equally applicable to EEAI. Accordingly, the Commission directs EEAI to establish a deferral account to capture any approved short term incentive amounts in revenue requirement that are not actually paid out, with these unpaid amounts to be returned to the benefit of customers. In addition, the Commission directs EEAI to reduce the weighting of the earnings component of its short term incentive program from 20 percent to 10 percent for 2011. The Commission directs EEAI to increase the activity measure and the individual employee performance measure by 5 percent each. The table below summarizes the Commission approved weightings for EEAI’s short term incentive program for 2011.

50 Application, page 118, paragraph 360. 51 Application, page 97, paragraph 293. 52 Decision 2008-031: EPCOR Energy Alberta Inc. 2007-2009 Regulated Rate Tariff Non-Energy Charge (Application No. 1512342) (Released: April 30, 2008).




Table 3. Short Term Incentive Weightings – EEAI Applied for and AUC Adjusted

A B C D

% Weight

% of Measure Included

% of Adjusted

Target STI Included

AUC Adjusted

Target STI EPCOR Utilities Net Earnings ($M) 40% 50% 20% 10% EEAI Activities 30% 100% 30% 35% Sub-total - Corporate and BU Points 70% 50% 45% Individual Employee Performance Rating 30% 100% 30% 35% Total 100% 80% 80%

122. The Commission notes EEAI’s statement that it has excluded 50 percent of the costs associated with the earnings component from its revenue requirement. The Commission approves EEAI’s approach in this regard.

123. The Commission approves the weightings for EEAI’s short term incentive program, as noted in Column D of Table 3 above, and the resulting short term incentive payment amounts in EEAI’s revenue requirement for 2010 and 2011.

5.3.3 Contractors, Other and Material Escalation 124. EDTI/EEAI retained Dr. David Ryan of the University of Alberta to provide forecast escalators to be used in the Application. The following table provides a summary of the forecast values for the various escalators that were recommended by Dr. Ryan:

Table 4. Summary of Escalators

2010 F 2011 F Contractor Costs 2.4% 3.3% Other Costs 1.7% 2.4% Material Costs 1.4% 3.5%

125. EEAI did not need to utilize the materials costs escalator in the RRT Application.

Commission Findings

126. In Decision 2010-505 the Commission approved the forecast escalators for contractor costs, other costs and materials costs for as filed by EDTI.

127. The Commission approves the escalators for contractor and other costs as filed by EEAI on the same basis as noted in Decision 2010-505.

5.4 International Financial Reporting Standards (IFRS) 128. In Decision 2010-505, the Commission considered EDTI’s proposed transition to IFRS in 2011 to be a reasonable approach, given the ongoing evolution of the requirements based on the existence of Exposure Drafts, the small impact resulting from the transition, and the inefficiency of delaying the implementation until the requirements are finalized because of the work already performed.



129. While IFRS deferral accounts were directed for EDTI transmission and distribution, due to the significantly smaller level of capital and therefore capital overheads, the Commission will not direct EEAI to utilize an IFRS deferral account, or to make any IFRS related adjustments related to its transition to IFRS in 2011.

6 ORDER

130. IT IS HEREBY ORDERED THAT:

(1) The Settlement Agreement (including Appendices A and B) attached as Appendix 2 to this Decision is approved as filed.

(2) EPCOR Energy Alberta Inc. shall refile its 2010-2011 RRT Application as

required by this Decision, on or before January 10, 2011, incorporating the findings and directions in this Decision.

(3) EPCOR Energy Alberta Inc.’s current 2010 Interim Regulated Rate Tariff,

approved in Decision 2009-255, shall continue pending approval of amended interim RRT non-energy rates as directed in this Decision.

Dated on December 16, 2010. ALBERTA UTILITIES COMMISSION (original signed by) Carolyn Dahl Rees Vice-Chair (original signed by) Bill Lyttle Commissioner (original signed by) Anne Michaud Commissioner



APPENDIX 1 – PROCEEDING PARTICIPANTS

Name of Organization (Abbreviation) Counsel or Representative

EPCOR Energy Alberta Inc. (EEAI)

J. Lowe Office of the Utilities Consumer Advocate (UCA)

R. McCreary Consumers’ Coalition of Alberta (CCA)

J. A. Wachowich ENMAX Energy Corporation (EEC)

G. Weismiller Consumer Intervenor Group (CIG) – Representing Consumers’ Coalition of Alberta Office of the Utilities Consumer Advocate Alberta Utilities Commission Commission Panel C. Dahl Rees, Vice-Chair B. Lyttle, Commissioner A. Michaud, Commissioner Commission Staff

V. Slawinski (Commission Counsel) D. Cherniwchan S. Allen J. Olsen B. Clarke P. Dmytruk



APPENDIX 2 – NEGOTIATED SETTLEMENT AGREEMENT

(return to text)

Appendix 2 - Negotiated Settlemen

(consists of 19 pages)

2010-2011 Non Energy RRT

EPCOR Energy Alberta Inc. Negotiated Settlement Agreement

Page 1 of 18

EPCOR ENERGY ALBERTA INC. 2010-2011 NON-ENERGY REGULATED RATE TARIFF

APPLICATION NO. 1605758NEGOTIATED SETTLEMENT AGREEMENT

BETWEEN:

EPCOR ENERGY ALBERTA INC. (“EEAI”)

-AND –

OFFICE OF THE UTILITY CONSUMER ADVOCATE (“UCA”), CONSUMER COALITION OF ALBERTA (“CCA”)

(the "Customer Intervenor Groups" or "CIG")

WHEREAS EEAI filed Application No. 1605758 (the "Application") with the Alberta Utilities

Commission ("AUC") with Proceeding ID. 436 requesting approval of EEAI's 2010-2011 non-

energy Regulated Rate Tariff;

AND WHEREAS EEAI and the CIG have reached a comprehensive negotiated settlement in

respect of all aspects of the Application;

NOW IN CONSIDERATION OF the mutual covenants set out in this Negotiated Settlement

Agreement (the “Agreement” or "Settlement Agreement"), EEAI and the CIG (collectively, the

"Parties") agree as follows:

1. This Agreement will apply to the 2010 and 2011 test years only. Except as otherwise expressly varied in this Agreement, the terms and parameters of the Application as amended by EEAI's responses to information requests filed in AUC Proceeding ID 436, will form the basis for the 2010 through 2011 Test Years.

2. Unless otherwise stated, all references in this Agreement to Schedules 1.1 to 1.6 refer to those Schedules in Appendix B. The Parties agree that the financial basis for this Agreement is reflected in Schedules 1.1 through 1.6 included in Appendix B to this Agreement as it adjusts EEAI’s Application and EEAI's responses to information requests filed in AUC Proceeding ID 436.

3. Except as otherwise expressly varied in this Agreement, the Parties agree that EEAI's Application and its responses to information requests filed in AUC Proceeding ID 436, including EEAI's Terms and Conditions and Fee Schedules, shall apply in 2010 and 2011. The agreed upon forecast non-energy revenue requirement for EEAI's non-energy Regulated Rate Tariff (“RRT”) for 2010 is $42.71 million and the agreed upon forecast non-energy revenue requirement for 2011 is $44.64 million; subject to Deferral Account

2010-2011 RRT Non-Energy Charge

EPCOR Energy Alberta Inc. Appendix 2 Page 1 of 19

AUC Decision 2010-571 (December 16, 2010)

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treatment of those matters specified in Appendix A; and subject to Common Matters/IFRS specified in section 12 below.

4. Deferral Accounts to be Continued

The Parties agree that the Deferral Accounts shown in Appendix A shall be continued for 2010 and 2011 and that EEAI shall maintain and ensure that the amounts contained in each Deferral Account will be tracked and accounted for separately from the other deferral accounts and also from each non-deferral account. It is further agreed that the Regulatory Project Deferral Account ("RPDA") shall only apply to the current regulatory project identified in the deferral account (i.e. the forecasted $0.43 million dollar TBC project in 2010) and that no operating costs are to be included in the RPDA. EEAI shall continue to recover the costs of this regulatory project in accordance with the terms of the RPDA, as approved by the EUB in Decision 2006-055. No additional regulatory projects shall be included in the RPDA unless approved by the Commission in a future rate proceeding, in accordance with the Electric Utilities Act. It is further understood and agreed that EEAI may recover future regulatory project expenses other than through the RPDA in accordance with orders and directions of the AUC.

5. Adjustments to EEAI's revenue requirement

The Parties agree that, for the purposes of the 2010 and 2011 Test Years, EEAI's revenue requirement will be adjusted for the following items:

(a) Process Improvement Forecast

The Process Improvement Forecast in the Operating Expenses forecast shall be increased by $300,000 for end of 2010 and 2011 as shown in Schedule 1.1 Row 11.

(b) Customer Service Costs

Customer Service Costs in the Operating Expenses forecast shall be reduced by $140,000 and $220,000 for end of 2010 and 2011 as shown in Schedule 1.1 Row 3 and supported by calculations in Schedule 1.2 Row 29. This adjustment reflects a decreased forecast Average Handle Time of 6.053 minutes in 2010 and 6.041 minutes in 2011 (Row 10) and a reduced forecast of live calls, 603,993 in 2010 and 538,353 in 2011 (Row 7). These adjustments result in a forecast reduction in the total telephone CSC hours required to 95,292 hours in 2010 and 85,660 hours in 2011 (Row 22) which in turn reduces the forecast CSC costs allocated to RRT customers.

(c) Credit Costs

Credit Costs in the Operating Expenses forecast shall be reduced by $150,000 in 2010 and $170,000 in 2011 as shown in Schedule 1.3 Row 6. This adjustment reflects a decrease from a credit cost rate of 250 basis points to 200 basis points in the credit costs for both 2010 and 2011.




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(d) Hearing Costs

Hearing Costs in the Operating Expenses forecast shall be reduced by $180,000 in 2010 as shown in Schedule 1.1 on a forecast basis, subject to deferral account treatment as stated in Appendix A.

(e) Bad Debt

Bad Debt in the Operating Expenses forecast shall be reduced by $560,000 and $680,000 for 2010 and 2011, respectively, as shown in Schedule 1.6 Row 13 on a forecast basis, subject to deferral account treatments as stated in Appendix A. This adjustment reflects the application of the 3:2:1 method, previously approved in Decision 2008-031 in respect of EEAI’s 2007-2009 Non-Energy General Tariff Application (GTA). EEAI may apply to the Commission for a further refinement to the bad debt expense deferral calculation mechanism for seasonal customers to address fluctuations in bad debt deferral account recoveries from this customer base. The CIG reserves the right to review and comment on the specific terms of this proposed further adjustment, when filed by EEAI.

(f) Customer Count

The Operating Expenses forecast shall be increased by $130,000 in 2010 and $210,000 in 2011 as shown in Schedules 1.4.2 Row 36. This adjustment reflects the removal of the additional 3% attrition adjustment for 2010, which increases the forecasted site counts by 0.5% in 2010 (Schedule 1.4.1 Row 32) and 1% in 2011 (Schedule 1.4.1 Row 33). This change in forecasted sites increases the variable portion of the Operating Expenses forecast and thus the forecast revenue requirement in both 2010 and 2011.

(g) Capital Additions

Capital Additions in the Operating Expenses forecast shall not be adjusted; provided that EEAI shall develop business cases for projects with a capital cost greater than $250,000 for EEAI's next Non-Energy GTA.

(h) Depreciation Expense and Cost of Debt

Depreciation Expense and cost of debt in the forecast shall be adjusted by $30,000 in 2010 and $20,000 in 2011 as shown in Schedule 1.1 Row 27. As discussed in CCA-EEAI-01b this adjustment reflects the 2009 Actual capital expenditures being $0.08 million lower than 2009 Updated Forecast primarily due to a $0.05 million decrease in the Web Self Serve project and a number of smaller variances. The impact on cost of debt and depreciation is a decrease of $0.03 million in 2010 and a decrease of $0.02 million in 2011.

(i) Non-Energy Return Margin

The Non-Energy Return Margin shall be calculated as 6% of all of EEAI's non-energy RRT operating costs, for each of the years 2010 and 2011. The amount of Non-Energy Return Margin including applicable taxes on the Non-Energy Return Margin based on the current forecast is $3.19 million in 2010 and $3.28 million in 2011 as shown in Schedule 1.5 Rows 10 and 12.




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(j) Debt Return on Equity

A Debt Return on Equity shall be calculated as the debt return rate of 6% applied to the 39% equity portion of EEAI’s rate base, corporate allocations and working capital. The Debt Return on Equity is $1.20 million in 2010 and $1.12 million in 2011 as shown in Schedule 1.5 Row 7.

(k) No-Cost Capital Adjustment

The parties could not agree to an adjustment for no-cost capital in respect of EEAI's collection of income taxes under the Future Income Tax method and request that the AUC hold a written process to determine this issue.

6. Limited Reopener

In the event that at any time during the years 2010 and 2011 that EEAI experiences a net gain or net loss of RRT or other site counts in the cumulative amount of plus or minus 250,000 sites (net of forecast attritions and growth forecast in EEAI's Application), this would constitute a significant change in circumstances from those contemplated in the 2010-2011 Rate Application and EEAI shall re-determine the increase or decrease in incremental cost and incremental revenues to serve the new site counts and apply to the AUC for new rates to reflect such change to RRT costs and revenues resulting from the change in circumstances. It is understood and agreed that other than the incorporation of the incremental costs and revenues to serve such cumulative increase or decrease in EEAI's sites, there shall be no other changes to the 2010-2011 revenue requirement as set out in this Agreement as a result of any increase or decrease of sites during the years 2010 and 2011.

7. Revision to Information Responses

EEAI shall revise certain information responses filed in the Application, as follows:

CCA-EEAI-20b Table CCA-EEAI-20-1

Community Consultation Services 2008A-2010F ($ millions)

A B C 2008A 2009UF 2010F

1 Revenue $0.18 $1.63 $1.26 2 Direct Costs $0.05 $0.66 $0.41 3 RRT Revenue Requirement Offset $0.04 $0.54 (1) $0.38

(1) Although calculated, this amount was inadvertently omitted from the 2009 Updated Forecast. This omission will be corrected in the 2010-2011 Refiling.

CCA-EEAI-25c(ii)

The asset life for the EEAI reserve imbalance should be 34.7 years, not 28 years (as shown in schedule 6.3) or 35.6 years (as shown in Table 7.1-1, L12). The schedules will be corrected at the time of EEAI’s Refiling.




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CCA-EEAI-29a

Income taxes should have been allocated using the Weighted Average allocator used for Return on Equity. EEAI will ensure that the proper allocator for income taxes is applied in its Refiling. The impact of this correction to the allocator is immaterial. See Table CCA-EEAI-29-1 for the calculation of the impact of this error.

Table CCA-EEAI-29-1 Impact of Income Tax Allocator Change

($ millions) A B Ref. 2010 F 2011 F 1 Return on Equity Allocated to RRT Customers Table 1.2.1-2 0.80 0.68 2 Tax Rate 28.0% 26.5% 3 1- tax rate 1 - B 72.0% 73.5% 4 Cost of Tax Allocated to RRT using Weighted Average Allocation 1 X 2 / 3 0.31 0.24 5 Cost of Tax Allocated using All Sites Table 1.2.1-2 0.31 0.25 6 Variance 0.00 (0.00)

UCA-EEAI-29 c)

Due to an oversight, EEAI did not update the forecast escalators during the preparation of the Application. The inflation escalators that should have been used are the actual “other” escalation factors of 1.7% and 2.4% for 2010 and 2011, respectively, rather than the average. EEAI has calculated the impact of this oversight. As discussed in section 3.1.1.1.4, the 2% escalation factor was applied to Paper Stock, Envelop Stock, Bill Printing, Insertion Cost and Manual Handling Costs. Applying the correct inflation factors to these costs results in a total decrease of $2,800 to these forecast costs in 2010 and an increase of $900 in 2011. EEAI will make this revision in its Refiling.

8. New Hires in Service Date

EEAI will adopt a mid-year in service date for all forecast staff additions created within EEAI for the purposes of its next GTA.

9. Capitalization of Incentive Payments

A portion of EEAI’s incentive compensation payments will be capitalized for the purposes of EEAI’s next GTA, consistent with its capitalization policy.

10. Working Capital Lead/Lags

EEAI will include leads (lags) associated with interest expense and income tax payments in the working capital calculation for the purposes of EEAI’s next GTA. Additionally, EEAI will review and update the components of the working capital calculation and make adjustments where warranted for the purposes of EEAI's next GTA.

11. No Prejudice to Future Rights

The Parties agree that specific revenue and cost adjustments in this Agreement are compromises between the Parties agreed to in order to achieve a settlement regarding the RRT non-energy revenue requirements for 2010 and 2011 only.




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This Agreement does not in any way prejudice the rights of either Party to pursue any issues of concern to them in any proceeding in respect of future Test Years or other matters, including EEAI's Energy Price Setting Plan (and, for greater certainty, including the return and risk margin for the Energy Price Setting Plan, which is not covered in this Agreement), which may be determined in a separate proceeding. Further, the Parties acknowledge that the revenue requirements agreed to and the components used to derive the revenue requirements do not establish a precedent for future regulatory proceedings.

12. Adjustments for Common Matters and IFRS:

(a) The 2010 and 2011 non-energy revenue requirements, including the adjustments set out in section 5 above, shall be subject to adjustment in the Compliance Filing for certain Common Matters that are determined in the Commission’s Decision in Proceeding ID. 437 (Application 1605759) dealing with the Distribution Tariff Application of EDTI, as set out in the AUC's letter dated May 28, 2010 regarding Common Matters Scope and Process (the "Common Matters").

(b) In addition to the Common Matters, EEAI will adopt the Commission’s decision in Proceeding ID. 437 (Application 1605759) dealing with the Distribution Tariff Application of EDTI with respect to the IFRS treatment of indirect capital overhead for the year 2011.

(c) As soon as the AUC makes its final determination on the Common Matters and IFRS treatment of indirect capital overheads in Proceeding ID. 437 (Application 1605759) dealing with the Distribution Tariff Application of EDTI, EEAI shall, in accordance with the time period set by the AUC, file the required 2010 and 2011 RRT rate adjustments with the AUC for implementation of final rates.

(d) It is agreed the current interim RRT rates will remain interim and refundable pending approval of the 2010 and 2011 RRT rates as adjusted for the Common Matters and IFRS treatment of indirect capital overheads following the AUC's decision in Proceeding ID. 437 (Application 1605759) dealing with the Distribution Tariff Application of EDTI.

13. Complete Information EEAI represents:

(a) The Application, supporting material, responses to information requests and all information filed with the AUC contains all material information and facts relied upon by EEAI to support its RRT revenue requirements for the 2010-2011 test years;

(b) To the knowledge of EEAI, the information provided by it in all of its filings with the AUC and during the negotiation of this Agreement and up to the date of this Agreement does not contain any untrue statement of fact;




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(c) At this time, EEAI has no plans or intentions and is not aware of any plans or intentions that would have, or potentially have, a material effect on its RRT revenue requirements for the 2010 and 2011 test years; and

(d) No Party has withheld any information relevant to this Agreement.

14. Reliance on Information

EEAI acknowledges that, in entering into this Agreement, the Parties to the Agreement relied on the documented information provided by EEAI to the Parties to the Agreement, as well as the representations of EEAI. In the event any of these representations or documented information are determined to be false or in the case that EEAI has omitted to provide the parties to the Agreement with any material information related to the RRT revenue requirements, revenues or accounting methods used by EEAI for the 2010 and 2011 test years, then any member of the parties to the Agreement may apply to the AUC to set aside the Agreement or to request such advice or directions from the AUC as the party considers appropriate.

15. No Material Changes

To the knowledge of EEAI, from the time the Application was filed up to and including the date of this Agreement, no events have occurred that materially affect EEAI’s RRT revenue requirement, revenues or accounting methods for the 2010 and 2011 test years.

16. Public Record Information

The Parties agree all correspondence, documentation or other information filed with the AUC in connection with Application No. 1605758 is part of the public record and will be available for use by any of the Parties in future rate proceedings.

17. Confidentiality

The terms and conditions of this Agreement are confidential and without prejudice until agreed to by each of the Parties. Upon agreement being reached amongst all of the Parties, EEAI will advise the AUC and request approval of the Agreement. Each of the Parties will support or otherwise not object to EEAI’s request for approval of the Agreement in all respects. For greater clarity, the Parties agree that all details of offers exchanged and discussions between the parties during the negotiated settlement process will remain strictly confidential.

18. Costs

EEAI will pay, on an interim refundable basis, the costs incurred by the CCA in negotiating matters within the scope and encompassed in this Agreement upon receipt of an invoice from CCA and provided the CCA indicates in writing the costs have been reasonably incurred and the cost claim complies with the AUC’s Rule 22. The invoice must be received by EEAI not later than 30 days after Reply Argument is submitted for the last of the Outstanding Matters.




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If the AUC does not approve all or a portion of the costs paid by EEAI to CCA under this section, then CCA will repay to EEAI the amount disallowed, including GST within 30 days of the AUC issuing its cost decision. EEAI will include the costs approved by the AUC in its hearing cost reserve account.

19. Entirety of Settlement

The Parties acknowledge that this Agreement is contingent on receipt of AUC approval of the entire Agreement as contemplated by Section 135 of the Electric Utilities Act. If the AUC rejects this Agreement in whole or in part or attaches any condition to its approval of this Agreement that materially affects the Agreement, all Parties are released from the terms of this Agreement and it shall have no further force or effect, unless all Parties hereto otherwise agree.

20. Compliance with Laws

The Parties agree that they shall comply with all applicable and valid laws, orders of courts or governments, and orders or directives of the AUC that affect or relate to this Agreement or EEAI's RRT obligations.

21. Miscellaneous

The Parties further agree:

(a) The division of this Agreement into headings and paragraphs is for convenience and reference only and should not affect the interpretation or construction of this Agreement;

(b) This Agreement and attached Appendices constitute the entire settlement between the Parties and no other agreements, expressed or implied, have been made;

(c) Any alteration or amendment of this Agreement must be in writing and signed by the Parties. This Agreement will be binding upon and enure to the benefit of the Parties and each of their respective successors and permitted assigns. A Party may not assign their rights and/or obligations under this Agreement without the consent of all other Parties, provided such consent is not unreasonably withheld;

(d) This Agreement may be executed in any number of counterparts;

(e) This Agreement is to be interpreted pursuant to the laws of the Province of Alberta;

(f) If any provision of this Agreement is found to be invalid by the AUC or a Court of Law and any Party determines that the invalidity of such provision materially affects this Agreement, the Parties agree to meet to negotiate a replacement provision that is intended to preserve the respective benefits and obligations of the Parties provided for under this Agreement and it will be read and interpreted as if the invalid provision were omitted;




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(g) The failure of any Party to exercise any right, power or option given to it under this Agreement or to insist upon the strict compliance with any of the terms or conditions in this Agreement will not constitute a waiver of any provisions with respect to any other or subsequent breach;

(h) Time will be of the essence in this Agreement and all its parts and no extension or variance of this Agreement will operate as a waiver of this provision with respect to any other or subsequent breach;

(i) Unless otherwise stated, any dollar amounts, prices or amounts stated under this Agreement are in the lawful currency of Canada;

(j) Unless otherwise stated, all accounting matters or terms in the Settlement will be interpreted and construed in accordance with generally accepted accounting principles in Canada;

(k) References to any statute, legislation or regulation include all subsequent additions, amendments, re-enactments and/or replacements enacted from time to time during the period covered by this Agreement; and

(l) The Parties agree that proper notice was provided with respect to the negotiation process that resulted in this Settlement Agreement













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Appendix ADeferral Account Treatment

� Hearing Costs (reserve account treatment) � Bad Debt Expense Deferral Account� Regulatory Project Deferral Account ("RPDA") for 2010 only




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Appendix BSchedule 1.1

Adjusted Costs Allocated to RRT 2010-2011 ($ millions)

A B C D E F G

Cost Category 2010 F 2011 F 2010 Adj.

2011Adj.

2010NSA

2011NSA

References

1 CUSTOMER SERVICE COST 2 Billing Services 8.01 8.13 8.01 8.13 3 Contact Centre 5.27 5.47 (0.14) (0.22) 5.13 5.25 NSA Sch. 1.2 R29 4 Collections 1.88 2.05 1.88 2.05 5 Technical Training & Communications 0.76 0.79 0.76 0.79 6 Information Services 4.78 4.93 4.78 4.93 7 Analytics 0.35 0.37 0.35 0.37 8 Management Expenses 2.68 3.13 2.68 3.13 9 Revenue Offsets (6.13) (5.66) (6.13) (5.66) 10 Site Count Adjustment 0.13 0.21 0.13 0.21 NSA Sch. 1.4.2 R36 11 Process Improvement Adjustment (0.30) (0.30) (0.30) (0.30) 12 Subtotal Customer Service Cost 17.61 19.22 (0.31) (0.31) 17.30 18.91 13 RRT OPERATION COST 14 RRT Operations Management 1.19 1.21 1.19 1.21 15 Load Validation & Settlement - - - - 16 Credit Costs 0.76 0.84 (0.15) (0.17) 0.61 0.67 NSA Sch. 1.3 R6 17 Unbillable Cost 0.22 0.20 0.22 0.20 18 Bad Debt 4.51 4.33 (0.56) (0.68) 3.95 3.65 NSA Sch. 1.6 R13 19 Subtotal RRT Operations Cost 6.68 6.57 (0.71) (0.85) 5.97 5.72 20 CORPORATE ALLOCATIONS 8.30 9.50 8.30 9.50 21 PROPERTY TAX & DEF ACCTS 22 Property Taxes 0.08 0.09 0.08 0.09 23 Hearing Cost Reserve 0.72 0.24 (0.18) - 0.54 0.24

24 Hearing Cost Reserve - Deferral Accounts (0.28) - (0.28) -

25 True-Up of Capital Projects (0.01) - (0.01) - 26 Subtotal Property Tax and Def Accts 0.52 0.33 (0.18) - 0.34 0.33 27 DEPRECIATION EXPENSE 5.01 4.61 (0.03) (0.02) 4.98 4.59 CCA-EEAI-01b28 RETURN & INCOME TAX 29 Cost of Working Capital 1.59 1.49 (0.78) (0.73) 0.81 0.76 30 Cost of Debt 0.83 0.71 0.83 0.71 31 Debt Return 1.20 1.12 1.20 1.12 NSA Sch. 1.5 R7 32 Equity Portion of Corporate AUF (1) (0.22) (0.27) (0.22) (0.27) 33 Return on Equity 0.80 0.68 (0.80) (0.68) - - 34 Cost of Tax 0.31 0.25 (0.31) (0.25) - - 35 Non-Energy Return Margin 6.25 6.57 (3.95) (4.16) 2.30 2.41 NSA Sch. 1.5 R10

36 Income Tax on Non-Energy Return Margin 2.43 2.37 (1.54) (1.50) 0.89 0.87 NSA Sch. 1.5 R12

37 Subtotal Return & Income Tax 12.22 12.06 (6.40) (6.47) 5.82 5.59 38 Total Cost 50.34 52.29 (7.63) (7.65) 42.71 44.64 39 $ per site per month 7.12 7.59 (1.11) (1.17) 6.01 6.42

(1) The Equity portion of Corporate AUF is included in Row 20 in Columns A and B




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Schedule 1.2 Summary of Calculation of Adjusted Average Handle Time,

Calls/Site, Telephone CSC Hours and Cost A B C D

References Description Calculation per

Filed Table 2010 F 2011 F 1 Table 3.1.2.3-1 Row 2 Total Sites per Year 10,052,932 9,905,764 2 Table 3.1.2.3-1 Row 5 Average Live Offered Calls/Site Actual/Forecast 0.063 0.061

3 Table 3.1.2.3-1 Row 6 Subtotal Live Calls (before adjustments) R2xR1 633,335 604,251

4 Table 3.1.2.3-1 Row 8 Call Reductions resulting from Web Customers Self Serve Table 3.1.2.3-2 R3 (15,728) (30,995)

5 Table 3.1.2.3-1 Row 9 Live Calls after Web Customer Self Serve R3+R5 617,607 573,257

6 Table 3.1.2.3-1 Row 10 Call Reductions resulting from Web Self Serve Enhancements Table 3.1.2.3-4 R3 (13,614) (34,904)

7 Table 3.1.2.3-1 Row 11 Forecast Live Calls R5+R6 603,993 538,353

8 Table 3.1.2.3-1 Row 12 Base Forecast Avg Handle Time(mins) 6.088 6.088

9 Table 3.1.2.3-1 Row 13

Average Handle Time Adjustment for Web Self Serve Enhancements (mins) Table 3.1.2.3-5 R5 (0.035) (0.047)

10 Table 3.1.2.3-1 Row 14 Average Handle Time (minutes) 6.053 6.041 11 Table 3.1.2.3-1 Row 15 Subtotal Base CSC Hours Required R10 x R7/60 60,933 54,203 12 Table 3.1.2.3-1 Row 16 Scheduling Adjustments 23,957 22,958

13 Table 3.1.2.3-1 Row 17 Required Phone Hrs to be Scheduled R11+R12 84,890 77,161

14 Table 3.1.2.3-1 Row 18 Shared Resourcing Hours Table 3.1.2.3-6 R6 (6,240) (6,240)

15 Table 3.1.2.3-1 Row 19 Borrowed Hours from Contact Centre Offline Table 3.1.2.3-6 R5 (11,131) (10,473)

16 Table 3.1.2.3-1 Row 21 Required Hours after Flexible Staffing Model R13+R14+R15 67,519 60,448

17 Table 3.1.2.3-1 Row 22 Shrinkage Percentage Table 3.1.2.3-7 34% 34% 18 Table 3.1.2.3-1 Row 23 Non-phone Paid Hours R16xR17 22,956 20,552

19 Table 3.1.2.3-1 Row 24 Subtotal Telephone CSC Required Hours R16+R18 90,475 81,001

20 Table 3.1.2.3-1 Row 27 New Hire Training Hours Table 3.1.2.3-1 R27 2,150 2,150 21 Table 3.1.2.3-1 Row 28 Loaned Hours Table 3.1.2.3-1 R28 2,667 2,509

22 Table 3.1.2.3-1 Row 29 Total Telephone CSC Required Hours R19+R20+R21 95,292 85,660

23 Table 3.1.2.3-1 Row 30 Average Salary $/Hour Table 3.1.2.3-1 R30 25.16 25.59 24 Table 3.1.2.3-1 Row 31 Average Benefits $/Hour Table 3.1.2.3-1 R31 5.530 5.760 25 Table 3.1.2.3-1 Row 34 CSC Salary and Benefits (millions) (R23+R24) X R22 2,924,517 2,685,425 26 Table 3.1.2.3-1 Row 34 CSC Salary and Benefits (millions) Filed Table 3,120,000 3,000,000 27 Reduction due to change in AHT, Calls/Site R26 - R25 195,483 314,575

28 CSC Allocated to RRT Schedule 2 / 2.1

R21 70.33% 69.57% 29 RRT portion of reduction in CSC Salary and Benefits R28 X R27 137,483 218,850




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Schedule 1.3Adjusted RRT DSO Credit Costs 2010-2011

($ millions) A B C D

2010 F 2011 F 2010NSA

2011NSA

1 Gross Financial Security Amount 39.94 43.08 39.94 43.08 2 Unsecured Credit Allowance 9.46 9.52 9.46 9.52 3 Net Financial Security Amount (row 1 – 2) 30.48 33.56 30.48 33.56 4 Credit Cost Rate 2.50% 2.50% 2.00% 2.00% 5 RRT DSO Credit Cost Amounts 0.76 0.84 0.61 0.67 6 $ Variance (0.15) (0.17)




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Schedule 1.4.1 Adjusted Site Count Forecast Reflecting Removal of 3% Attrition Adjustment

A B C D E

Month

2010-2011GTA RRO

Site FC

2010-2011 GTA RRO Site Forecast without 3%

AdjustmentSite Count Variance

Site Count % Variance

Schedule 7.1 * B-C D/B 1 Jul-09 594,785 594,785 - 0.0% 2 Aug-09 594,607 594,607 - 0.0% 3 Sep-09 594,434 594,434 - 0.0% 4 Oct-09 594,261 594,261 - 0.0% 5 Nov-09 594,089 594,089 - 0.0% 6 Dec-09 593,918 593,918 - 0.0% 7 Jan-10 597,430 597,681 251 0.0% 8 Feb-10 595,950 596,662 712 0.1% 9 Mar-10 594,474 595,645 1,171 0.2%

10 Apr-10 592,952 594,596 1,644 0.3% 11 May-10 591,436 593,549 2,114 0.4% 12 Jun-10 589,923 592,505 2,581 0.4% 13 Jul-10 588,416 591,462 3,047 0.5% 14 Aug-10 586,888 590,405 3,518 0.6% 15 Sep-10 585,389 589,368 3,979 0.7% 16 Oct-10 583,895 588,333 4,437 0.8% 17 Nov-10 582,406 587,300 4,894 0.8% 18 Dec-10 580,921 586,269 5,348 0.9% 19 Jan-11 579,668 585,233 5,565 1.0% 20 Feb-11 578,703 584,257 5,554 1.0% 21 Mar-11 577,740 583,284 5,544 1.0% 22 Apr-11 576,747 582,280 5,533 1.0% 23 May-11 575,756 581,278 5,522 1.0% 24 Jun-11 574,767 580,279 5,512 1.0% 25 Jul-11 573,781 579,282 5,501 1.0% 26 Aug-11 572,780 578,270 5,490 1.0% 27 Sep-11 571,799 577,278 5,479 1.0% 28 Oct-11 570,819 576,287 5,469 1.0% 30 Nov-11 569,841 575,299 5,458 1.0% 31 Dec-11 568,866 574,314 5,447 1.0% 32 2010 Average 589,173 591,981 2,808 0.5% 33 2011 Average 574,272 579,778 5,506 1.0%

*2010-2011 GTA RRO Site Forecast without 3% Adjustment calculated by removing 3% from attrition percentages in Table 1.5.7.1.1-2 for 2010F.




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Schedule 1.4.2 Revenue Requirement Impact of Removal of 3% Attrition Adjustment

A B C D

Site

Variability Site

Variability Cost Category Reference 2010 F* 0.5% 2011 F* 1.0%

1 CUSTOMER SERVICE COST 2 Billing Services Table 1.2.1-2 8.01 0.03 8.13 0.06 3 Contact Centre Table 1.2.1-2 5.27 0.02 5.47 0.05 4 Collections Table 1.2.1-2 1.88 0.01 2.05 0.01

5Technical Training and Communications Table 1.2.1-2 0.76 0.00 0.79 0.00

6 Information Services Table 1.2.1-2 4.78 0.01 4.93 0.03 7 Analytics Table 1.2.1-2 0.35 0.00 0.37 0.00 8 Management Expenses Table 1.2.1-2 2.68 0.01 3.13 0.01 9 Revenue Offsets Table 1.2.1-2 (6.13) - (5.66) (0.05) 10 Subtotal Customer Service Cost Table 1.2.1-2 17.61 0.08 19.22 0.12 11 RRT OPERATIONS COST Table 1.2.1-2 12 RRT Operations Management Table 1.2.1-2 1.19 0.00 1.21 0.01 13 Load Validation & Settlement Table 1.2.1-2 - - - - 14 Credit Costs Table 1.2.1-2 0.76 0.00 0.84 0.01 15 Unbillable Cost Table 1.2.1-2 0.22 0.00 0.20 0.00 16 Bad Debt Table 1.2.1-2 4.51 0.02 4.33 0.04 17 Subtotal RRT Operations Cost Table 1.2.1-2 6.68 0.03 6.57 0.06 18 CORPORATE ALLOCATIONS Table 1.2.1-2 8.30 - 9.50 -

19PROPERTY TAX & DEF ACCTS Table 1.2.1-2

20 Property Taxes Table 1.2.1-2 0.08 - 0.09 - 21 Hearing Cost Reserve Table 1.2.1-2 0.72 - 0.24 -

22Hearing Cost Reserve - Deferral Accounts Table 1.2.1-2 (0.28) - - -

23 True-Up of Capital Projects Table 1.2.1-2 (0.01) - - - 24 Subtotal Property Tax & Def Acct Table 1.2.1-2 0.52 - 0.33 -25 DEPRECIATION EXPENSE Table 1.2.1-2 5.01 - 4.61 -26 RETURN & INCOME TAX Table 1.2.1-2 27 Cost of Working Capital Table 1.2.1-2 1.59 0.00 1.49 0.01 28 Cost of Debt Table 1.2.1-2 0.83 - 0.71 - 29 Return on Equity Table 1.2.1-2 0.80 - 0.68 - 30 Cost of Tax Table 1.2.1-2 0.31 - 0.25 - 31 Return Margin Table 1.2.1-2 6.25 0.01 6.57 0.02 32 Income Tax on Return Margin Table 1.2.1-2 2.43 0.00 2.37 0.01 33 Subtotal Return & Income Tax Table 1.2.1-2 12.22 0.02 12.06 0.04 34 Total Cost Table 1.2.1-2 50.34 0.13 52.29 0.21 35 $ per site per month Table 1.2.1-2 7.12 7.59 36 Revenue Requirement Impact 0.13 0.21 37 RRT Sites Schedule 7.1 589,173 574,272 38 RRT Sites + % change Row 37 x (1+%) 591,981 579,778 39 Decrease in $ per site per month -R36 / R38 / 12 (0.018) (0.031) *2010 and 2011 Forecasts pulled from Tables CCA-EEAI-03-2 and CCA-EEAI-03-3




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Schedule 1.5 Adjusted Non-Energy Return Margin Methodology

($ millions) A B C Ref 2010 2011

Debt Return on Equity 2010-2011 1 EEAIRate Base Allocated to RRT Table AUC-EEAI-20-2 R3 22.73 19.29 2 Working Capital Allocated to RRT Table 7.3.1-1 R2 22.21 20.76 3 Corporate Rate Base Allocated to RRT Table AUC-EEAI-20-5 R24 6.16 7.72 4 Total Rate Base Allocated to RRT R1 + R2 + R3 51.10 47.77 5 Capital Structure Equity Table 7.3.1-1 R4 39% 39% 6 Debt Rate Table 7.3.1-1 R7 6% 6% 7 Debt Return on Equity Portion of Assets R4 x R5 x R6 1.20 1.12

RRT Non-Energy Return Margin 2010-2011

8 Operating Costs

NSA Schedule 1.1 R12 + R19 + R20 + R26 + R27 + R29 + R30 + R32 38.32 40.24

9 After-Tax RRT Non-Energy Return Margin % Decision 2010-055, para 115 6.00% 6.00% 10 RRT Non-Energy Return Margin R8 x R9 2.30 2.41 11 Income Tax Rate Table 7.3.4-1 R3 28% 26.50% 12 Income Tax on RRT Non-Energy Return Margin R10/(1-R11) x R11 0.89 0.87 13 Total Non-Energy Return & Income Tax R7 + R10 + R12 4.39 4.40

Schedule 1.6 Adjusted Forecast Bad Debt using 2009, 2008, 2007 3:2:1 Weighting

($ millions) A B C D E F

2010 Forecast 2011 Forecast

Rate Class

Forecast Bad Debt

%Forecast Revenue

Forecast Bad Debt

Forecast Bad Debt

%Forecast Revenue

Forecast Bad Debt

EDTI Service Area 1 Residential 0.71% 206.09 1.47 0.71% 186.52 1.33 2 Small Commercial 0.30% 87.39 0.27 0.30% 77.87 0.24 3 Lighting 0.06% 0.89 0.00 0.06% 0.73 0.00 4 EDTI Total 0.59% 294.36 1.74 0.59% 265.12 1.57

Fortis Service Area 5 Residential 0.46% 312.80 1.43 0.46% 293.18 1.34 6 Farm 0.24% 88.20 0.21 0.24% 84.93 0.20 7 Irrigation 0.32% 11.45 0.04 0.32% 9.95 0.03 8 Small Commercial 0.43% 124.22 0.53 0.43% 117.92 0.50 9 Oil and Gas 0.04% 2.25 0.00 0.04% 2.07 0.00 10 Lighting 0.32% 4.47 0.01 0.32% 4.65 0.01 11 Fortis Total 0.41% 543.40 2.22 0.41% 512.70 2.09 11 EEAI Total 0.47% 837.77 3.95 0.47% 777.81 3.65 12 Filed Total 4.52 4.33 13 Variance (0.56) (0.68)




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EPCOR Energy Alberta Inc. - AUC · 2018. 2. 23. · ALBERTA UTILITIES COMMISSION Decision 2010-571:...

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