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MADE at the City of Calgary, in the Province of Alberta, on

ALBERTA ENERGY AND UTILITIES BOARD

EUB Order U2007-368 of 12

Electric – Miscellaneous Rates Order U2007-368

ENMAX Energy Corporation 2007-2008 Non-Energy Regulated Rate Option Negotiated Settlement Agreement

Application No. 1522895

1 INTRODUCTION AND DETAILS OF THE APPLICATION

By letter dated August 17, 2007, ENMAX Energy Corporation (EEC) filed an application (Application) with the Alberta Energy and Utilities Board (EUB or the Board) requesting approval of a negotiated settlement agreement in regard to the non-energy portion of EEC’s 2007-2008 regulated rate option tariff (RROT). In Order U2007-53,1 dated February 22, 2007, the Board approved EEC’s request to commence a negotiated settlement process (NSP) in respect of EEC’s non-energy RRO for the years 2007-2010. The Board noted in Order U2007-53 that it had received statements of intention to participate in the NSP from the following three parties: the Consumers Coalition of Canada (CCA), the Public Institutional Consumers of Alberta (PICA) and the Office of the Utilities Consumer Advocate (UCA). Additionally, in Order U2007-53, the Board ordered that EEC file the results of the NSP no later than June 1, 2007. On June 8, 2007, EEC advised the Board by letter that as of June 1, 2007, it had not reached a settlement with all parties. EEC requested an extension to June 22, 2007 in order to continue negotiations. By letter dated June 14, 2007, the Board granted the extension requested by EEC and directed EEC, in the event that negotiations were not successful, to file its RROT Application no later than August 17, 2007. After further settlement discussions with the CCA, the UCA and PICA (collectively, the Consultation Parties), EEC and the Consultation Parties entered into a comprehensive and unanimous negotiated settlement of EEC’s non-energy RROT for the period from January 1, 2007 to December 31, 2008 (Settlement or NSA). This Settlement was reflected in Terms of Settlement dated August 14, 2007, which have been executed by EEC and the Consultation Parties, and were attached as Appendix “A” to the Application. EEC applied for approval of the Terms of Settlement and approval of a non-energy revenue requirement and rates determined in accordance with those Terms of Settlement.

1 Order U2007-53 – ENMAX Energy Corporation Request to Initiate a Negotiated Settlement Process in respect

of the Non-Energy Portion of the 2007-2010 Regulated Rate Option Application (Application No. 1498132) (Released: February 22, 2007)

24th day of December 2007.

of 12 EUB Order U2007-368

As summarized in the Settlement Brief included in the Application, the material provisions of the Terms of Settlement included the following:

• a two year term commencing January 1, 2007 and ending December 31, 2008; • a formula based approach to determine the 2007 and 2008 non-energy revenue

requirements; • 2007 and 2008 billing and customer care (B&CC) costs and “Other Costs” determined in

accordance with the Terms of Settlement; • a cap on B&CC costs and a provision for cost sharing between EEC and eligible

customers; • a $23.434 million non-energy revenue requirement for 2007 (including margin); • a 6% margin on non-energy revenue requirement for each of the years 2007 and 2008; • a process for reviewing RROT terms and conditions; and • the right of a party to conduct an audit to ensure EEC’s compliance with the Terms of

Settlement.

The Board issued the Notice of Application to interested parties on August 24, 2007, according to the Board’s distribution list for previous EEC non-energy RROT applications, those being Application Nos. 13805232 and 1455154.3 In addition, the Notice of Application was published in the Edmonton Journal on August 30, 2007 and the Edmonton Sun, the Calgary Herald and the Calgary Sun on August 31, 2007. The Board received no objections to the Application. On September 26, 2007, the EUB issued information requests (IRs) to EEC regarding the Application. EEC responded to these IRs on the Board’s deadline of October 15, 2007. The other parties to the Settlement were requested to file separate responses if they did not agree with any of the responses submitted by EEC. None of the other parties filed any separate responses. On October 26, 2007, the EUB issued supplemental IRs to EEC regarding some of the responses submitted to the initial IRs. EEC provided responses to these supplemental IRs on November 9, 2007. The other parties to the Settlement were requested to file separate responses if they did not agree with any of the responses submitted by EEC. None of the other parties filed any separate responses. On December 14, 2007, EEC issued an e-mail to representatives of the CCA, PICA and the UCA, to which EEC attached a document outlining the proposed wording changes to the Terms of Settlement that resulted from the IR process. EEC requested that the parties review the proposed changes and indicate whether or not they accepted them. Representatives of the CCA and PICA responded electronically on December 19, 2007, while the UCA’s representative responded electronically on December 20, 2007. For administrative purposes of this Order, the Board considers the record of the proceeding to have closed on December 20, 2007.

2 Application No. 1380523 – 2005 Regulated Rate Tariff Non-Energy (Decision 2006-001, Released: January 13,

2006) 3 Application No. 1455154 – 2006 Regulated Rate Tariff Non-Energy (Decision 2006-104, Released: October 24,

2006)


2 VIEWS OF THE BOARD

Section 132 of the Electric Utilities Act, S.A. 2003, c. E-5.1 requires the Board to establish rules, practices and procedures that facilitate settlements. These rules have been established by the Board in Directive 018 – Negotiated Settlement Rules, dated December 19, 2006. Section 6 of the Negotiated Settlement Rules provides the following guidance with respect to the evaluation and acceptance of a settlement agreement:

6.1 Once an application is filed, the Board will provide notice of the application. 6.2 The Board will consider dissenting views in its consideration of a settlement agreement. The dissent might relate to one issue, portions of the settlement agreement, or its entirety. The Board will determine the process for dealing with the issues identified by nonparticipants or parties with dissenting views. If it determines that a hearing is not required, the Board will consider such views in its deliberations. If it determines that a hearing is required, either oral or written, these parties will have the opportunity to offer evidence and to question all or any portion of the settlement. 6.3 Upon presentation of a unanimous settlement or a settlement that is unopposed, the Board will then assess whether the settlement results in rates and terms and conditions that are just and reasonable. If a unanimous settlement is determined by the Board to be patently against the public interest or contrary to law, the Board will intervene.

As the Settlement is comprehensive and unanimous, with no unresolved issues and no dissenting views, the Board has considered the Settlement according to Section 6.3 of the Negotiated

Settlement Rules (the Rules). The Board first must be satisfied that the NSP was conducted fairly and in accordance with the Rules. Then the Board must be satisfied that the rates and terms and conditions of service resulting from the Settlement are not patently contrary to the public interest. Fairness of the NSP

As indicated in Section 1 of this Order, the Board published the Notice of Application as required by the Rules. In addition, EEC published a notice in both the Calgary Sun and the Calgary Herald in which EEC provided information regarding its intention to commence negotiations with interested parties.4 In accordance with Section 4.1 of the Rules, the Board observer has confirmed that, in the observer’s view, the NSP was conducted fairly. The Board is satisfied that the materials filed in the Application, and the attendance of Board staff provide a level of assurance that interested parties were provided with the opportunity to have their issues addressed in the NSP. Accordingly, the Board is satisfied that the NSP was conducted fairly and in accordance with the Rules. Are the Terms of Settlement in the Public Interest?

Schedule “B” of the Terms of Settlement sets out the 2007 non-energy revenue requirement agreed to by the parties. The EUB considers that a good comparator to this 2007 non-energy

4 As referred to by EEC on page 2 of the Application, with copies of the Notice being included in Appendix “B”

of the Application


revenue requirement would be the 2006 approved non-energy revenue requirement. In connection with this comparison, the EUB has prepared the following table: Table 1. 2007 Agreed to Revenue Requirement Compared to the 2006 Board Approved Revenue Requirement

Item

2006 Approved (As Restated)

($000’s)

2007 NSA ($000’s)

2007 NSA vs. 2006 Approved

Revenue Requirement Impact

Increase/(Decrease) ($000’s)


Increase/(Decrease) (%)

Billing and Customer Care 15,199 16,062 863 5.7

Shared Services 2,938 3,050 112 3.8

Depreciation and Interest 1,713 1,781 68 4.0

Operational Costs 1,808 1,877 69 3.8

Hearing Costs 324 388 64 19.8

Working Capital (19) (20) (1) 5.3

Revenue Offsets (2,869) (2,550) 319 (11.1)

Bad Debts 1,464 1,520 56 3.8

Margin 1,233 1,326 93 7.5

GRAND TOTAL 21,791 23,434 1,643 7.5

Sources: 2006 Approved – Appendix 4 of Decision 2006-104; 2007 NSA – Schedule B of the Terms of Settlement

In preparing this table, the Board restated the approved amounts for 2006 for the B&CC costs as well as the depreciation and interest costs. The B&CC costs were increased by $988,000 from the $14,211,000 approved in Decision 2006-104 and the depreciation and interest costs were reduced by $988,000 from the $2,701,000 approved in Decision 2006-104. This restatement is based on the response provided to BR-EEC-012, in which EEC indicated that, for the purposes of the negotiations, depreciation that was directly attributable to B&CC was added into that category and deducted from the general depreciation category. The $988,000 is the sum of the amounts approved by the Board in Decision 2006-104 for depreciation on the ENMAX Encompass assets ($704,000) as well as the transition fee amortization ($284,000).5 The average number of customers for 2006 (approved) and 2007 (agreed to in the Settlement) are as shown in the following table:

5 The two figures quoted above of $704,000 and $284,000 are shown on page 2 of 2 of the response to BR-EEC-

042(a) Attachment B of Application No. 1455154


Table 2. 2007 Agreed to Average Number of Customers Compared to the 2006 Board Approved Average Number of Customers

Item

2006 Approved Average # of Customers

2007 NSA

Average # of Customers

2007 NSA vs. 2006 Approved (Decrease) in

Average # of Customers


(Decrease) %

Residential 289,730 277,695 (12,035) (4.2)

Commercial 16,219 15,542 (677) (4.2)

TOTAL 305,949 293,237 (12,712) (4.2)

Sources: 2006 Approved – Appendix 4 of Decision 2006-104; 2007 NSA – Schedule B of the Terms of Settlement

The associated rates are as shown in the following table: Table 3. 2007 Agreed to Rates Compared to the 2006 Board Approved Rates

Item

2006 Approved $ per day

2007 NSA $ per day


Increase $ per day


Increase %

Residential Rate .1956 .2192 .0236 12.1

Commercial Rate .1870 .2135 .0265 14.2

Sources: 2006 Approved – Appendix 4 of Decision 2006-104; 2007 NSA – Appendix D of the Application

Billing and Customer Care Costs

The majority of the $1.643 million increase in the revenue requirement between the 2006 approved amount and the 2007 NSA amount is due to the $0.863 million increase in B&CC costs. The B&CC approved cost per customer was $54.67 for 20056 and $49.68 for 20067 while the 2007 NSA amount is $54.77.8 In its 2006 RROT non-energy application,9 EEC attributed the decrease in the 2006 forecast B&CC cost per customer to a decrease in RRO customers, which resulted in a smaller proportion of the total ENMAX B&CC costs being allocated to the RRO.10 The 2006 actual average number of customers for the RRO was 315,59211 while the 2006 approved figure was 305,949 as shown in Table 2 above. In the Board’s view, the fact that the 2006 actual average number of customers was higher than the approved forecast contributed to the 2006 actual B&CC cost per customer of $52.7712 being higher than the $49.68 approved for 2006. Consequently, the Board considers that the actual $52.77 B&CC cost per customer for 2006 is reasonable compared to the 2006 approved amount. In the Terms of Settlement, the $52.77 figure was used as the basis for the 2007 NSA B&CC cost per customer, to which inflation of 3.8% was applied.13 On the face of it, the Board would have expected the 2007 B&CC cost per customer to decrease from the 2006 actual amount, given

6 The cost per customer is shown on page 3 of the Responses to RRT Board Directives section of Application No.

1446443 – ENMAX Energy Corporation 2005 Regulated Rate Tariff Non-Energy Refiling (Decision 2006-022, Released: March 14, 2006)

7 Costs (from Table 1) of $15,199,000 divided by customers (from Table 2) of 305,949 8 Costs (from Table 1) of $16,062,000 divided by customers (from Table 2) of 293,237 9 Application No. 1455154 10 Section 4, page 24 of 74 of Application No. 1455154 11 Application No. 1510983 – ENMAX Energy Corporation 2006 Annual Financial and Operating Reporting for

Directive 014 – Schedule 6, Residential customers of 297,572, Commercial customers of 18,020 12 As shown by EEC in Section 5(a)(i) of the Terms of Settlement 13 As shown by EEC in Section 5(a)(i) of the Terms of Settlement


that the number of customers forecast for 2007 is lower than the 2006 actual amount. However, the Terms of Settlement includes a mechanism that allows the actual 2007 B&CC cost per customer to be compared to the 2007 NSA amount, which could result in a decrease or an increase to the 2007 revenue requirement if certain conditions are met.14 The Board considers that both customers and EEC are treated fairly by this mechanism. As a result of this analysis, the Board finds that the B&CC costs calculated for the 2007 NSA as shown in Table 1 above are reasonable and not patently contrary to the public interest. The formula for the 2008 forecast B&CC costs, as shown in Section 6(a)(i) of the Terms of Settlement, was subsequently acknowledged by EEC to be incorrect in the response to BR-EEC-003. The Board considers that in preparing the response to BR-EEC-003, EEC meant to use $54.78 * (1+X) * Y instead of the $53.78 * (1+X) * Y it provided. Consequently, the Board considers that for purposes of the Terms of Settlement, the correct formula that should be used in Section 6(a)(i) is $54.78 * (1+X) * Y. The Terms of Settlement include a mechanism that allows the actual 2008 B&CC cost per customer to be compared to the 2008 NSA amount, which could result in a decrease or an increase to the 2008 revenue requirement if certain conditions are met.15 The Board considers that both customers and EEC are treated fairly by this mechanism. As a result, the Board considers that the formula for the 2008 B&CC costs is reasonable and not patently contrary to the public interest. Hearing Costs

The 2007 NSA hearing costs of $388,000 consist of the 2006 approved amount of $324,000 plus $50,000 for a total of $374,000 to which inflation of 3.8% was applied.16 The forecast for the 2008 hearing costs is simply the $388,000 for 2007 to which an inflation factor is applied.17 Sections 6(a)(v) and 7(a)(iv) of the Terms of Settlement will be used to reflect the actual inflation rates for 2007 and 2008. While it is not clear to the Board why an additional $50,000 was added to the 2006 base costs in calculating the 2007 revenue requirement, the Board does note that Sections 6(a)(vi) and 7(a)(v) of the Terms of Settlement will be used to reflect the actual hearing costs that are approved for 2007 and 2008. The EUB considers that the effect of these sections of the Terms of Settlement result in the hearing costs being treated in the same manner as they previously were, that being similar to a reserve account where only the approved hearing costs are collected from customers. The EUB considers that this treatment of hearing costs is reasonable and not patently against the public interest. Revenue Offsets

The EUB notes that the 2007 NSA revenue offsets of $2,550,000 consist of the 2006 approved amount of $2,869,000 less $412,000, for a total of $2,457,000 to which inflation of 3.8% was applied.18 The forecast for the 2008 revenue offsets is simply the $2,550,000 for 2007 to which an inflation factor is applied.19 EEC described the $412,000 adjustment as being a reflection of the elimination of application fees. In its May 19, 2006 submission in regard to its 2006 RRO

14 As detailed in Section 6(a)(iv) of the Terms of Settlement 15 As detailed in Section 7(a)(ii) of the Terms of Settlement 16 As detailed in Section 5(a)(ii) of the Terms of Settlement 17 As detailed in Section 6(a)(ii) of the Terms of Settlement 18 As detailed in Section 5(a)(ii) of the Terms of Settlement 19 As detailed in Section 6(a)(ii) of the Terms of Settlement


non-energy application,20 EEC indicated that it collected a $10 application fee per request that applied when a customer requested a new service. In the same submission, EEC stated that Section 19(1)(a) of the Regulated Rate Option Regulation required that effective July 1, 2006, “an owner must not, either in its regulated rate tariff or by other means, collect fees related to the entry to, or exit from, the regulated rate tariff by an eligible customer.” Accordingly, EEC advised that it would not be collecting such an application fee effective July 1, 2006. The EUB understands that the $412,000 was the forecasted application fees for January 1, 2006 to June 30, 2006 included in EEC’s 2006 approved amount.21 The EUB considers that it is appropriate to exclude the $412,000 from the determination of the 2007 revenue requirement as application fees are no longer being collected by EEC. The EUB is aware that Sections 6(a)(v) and 7(a)(iv) of the Terms of Settlement will be used to reflect the actual inflation rates for 2007 and 2008. The EUB believes that this treatment is fair to both customers and the utility as it eliminates any forecast risk with respect to the inflation rate. Consequently, the EUB considers that this treatment of revenue offsets is reasonable and not patently contrary to the public interest. Margin

The parties agreed to apply a 6% margin to non-energy revenues for both 2007 and 2008, which is consistent with the non-energy margin approved for 2004,22 2005, 23 and 2006.24 The Board considers that this percentage is still reasonable and not patently contrary to the public interest. Other Costs

The other costs included in Table 1 above consist of the following: shared services, depreciation and interest, operational costs, working capital, and bad debts. The total 2006 approved amount for these combined costs was $7,904,000 and the 2007 NSA amount is $8,208,000. The increase of $304,000 is 3.8%, which corresponds to section 5(a)(ii) of the Terms of Settlement. The forecast for these costs in 2008 is simply the $8,208,000 for 2007 to which an inflation factor is applied. The Board considers that limiting the increase in these costs to inflation is reasonable. Sections 6(a)(v) and 7(a)(iv) of the Terms of Settlement will be used to reflect the actual inflation rates for 2007 and 2008. The EUB believes that this treatment is fair to both customers and the utility as it eliminates any forecast risk with respect to the inflation rate. Consequently, the EUB considers that this treatment of other costs is reasonable and not patently against the public interest. Average Number of Customers

As shown in Table 2 above, the average number of customers for the 2007 NSA is 4.2% lower than the 2006 approved amount. The 2006 actual average number of customers, as outlined above, is 315,592. The resulting difference between the 2007 NSA amount and the 2006 actual amount is a decrease of 22,355, or 7.1%. The 2005 actual average number of customers was

20 Application No. 1455154 21 As noted in EEC’s submission of May 19, 2006 in Application No. 1455154 22 Page 48 of Decision 2004-065, ENMAX Energy Corporation – 2004 Regulated Rate Tariff Part C: Non-Energy

Costs and Terms and Conditions (Released: August 13, 2004) (Application No. 1306818) 23 Page 38 of Decision 2006-001 24 Page 25 of Decision 2006-104


347,459.25 The resulting decrease between the 2005 actual and the 2006 actual was, therefore, 9.2%. All else being equal, the Board would have expected the decrease for the NSA 2007 to be greater. However, in the calculation of the B&CC costs adjustments for 2007 and 2008, as outlined in Sections 6(a)(iv) and 7(a)(ii) of the Terms of Settlement, the actual customer counts will be used. The Board considers that this approach eliminates a significant portion of the risk associated with the customer forecast and it is fair to both customers and the utility. Consequently, the Board considers that the customer forecast for 2007 is reasonable and not patently against the public interest. The forecast 2008 customer count was scheduled to be determined and provided to the Consultation Parties by November 15, 2007.26 The EUB notes that as detailed in Section 8 of the Terms of Settlement, the Consultation Parties will have the opportunity to discuss with EEC any concerns with the 2008 customer count and any unresolved concerns can be directed to the EUB. The Board considers this approach to be fair and reasonable. Customer Rates

The Settlement will result in increased customer rates for 2007 as shown in Table 3 above. In BR-EEC-011, EEC indicated that it has agreed to use the same methodology approved in the 2006 RRO with respect to allocating the revenue requirements to the two rate classes. As shown in Table 3 above, this results in the increases for 2007 for the two rate classes being in the 12% - 14% range. In the Board’s view, the rate increases in 2007 are driven by both an increase in the revenue requirement for 2007 and a decrease in the number of customers, both of which the Board has earlier in this Order found to be reasonable. Therefore, the EUB does not find these increases in customer rates to be patently contrary to the public interest. The Board also takes comfort that the Consultation Parties represented a cross section of EEC’s customers and these groups agreed to the Terms of Settlement, including the resulting rates for 2007. The Board cannot comment on the forecast rates for 2008 as these have not been determined yet, but the Board does note that the Terms of Settlement includes a mechanism for finalizing rates with the Consultation Parties, and the Board, if necessary. Other Items in the Settlement

U2007-109 Adjustment

EEC has included an adjustment relating to Order U2007-10927 in calculating the 2008 non-energy revenue requirement.28 This adjustment relates to any discrepancy between shortfalls referred to in Order U2007-109 and the amounts collected through the riders implemented under that Order.

25 Section 3, table 3.10 on page 18 of 74 of Application No. 1455154 has residential customers of 327,401; table

3.12 on page 19 of 74 of Application No. 1455154 has commercial customers of 20,058. 26 As detailed in Section 8 of the Terms of Settlement 27 Order U2007-109 – ENMAX Energy Corporation 2006 Regulated Rate Option Non-Energy Rate Rider True-up

(Application 1500728) (Released: April 19, 2007) 28 As detailed in Section 6(a) of the Terms of Settlement


The riders implemented under Order U2007-109 were approved for the period May 1, 2007 to December 31, 2007, and the Board directed EEC to include the amount of any discrepancy as a revenue offset in EEC’s next GTA. The Board considers EEC’s proposal to include any discrepancy as an adjustment to the 2008 non-energy revenue requirement to be in accordance with the Board’s direction in U2007-109. Therefore, the Board has no concern with this adjustment. Adjustments to the 2009 Non-Energy Revenue Requirement

In Section 7 of the Terms of Settlement, EEC has outlined a number of adjustments relating to 2008 that it is proposing be included in the 2009 non-energy revenue requirement. These adjustments relate to differences between actual and forecast inflation, actual and forecast hearing costs, and actual and forecast B&CC costs. The Board has reviewed these adjustments and considers that they are consistent with the adjustments relating to 2007 that are proposed to be included in the 2008 non-energy revenue requirement. Income Tax

Section 10 of the Terms of Settlement outlines the agreement as it relates to income tax. In effect, Section 10 provides that parties agree that if EEC becomes liable to make income tax payments for 2007 and 2008 under the Payment in Lieu of Tax Regulation, then EEC may apply to recover those payments as part of its 2009 non-energy revenue requirement. Under Section 10, the Consultation Parties have the right to make submissions regarding the assumptions, calculations and methods used for determining any income taxes. The EUB considers that this approach is fair and reasonable and not patently contrary to the public interest. Terms and Conditions (T&C)

Section 12 of the Terms of Settlement provides that if EEC and the Consultation Parties were unable to agree upon amendments to the T&C and Fee Schedule by September 30, 2007, EEC may file amendments to these documents for EUB approval. In response to BR-EEC-001, EEC indicated that no agreement was reached by September 30, 2007, and that it expected to apply to the Board for approval of the revised T&C and Fee Schedule before the end of 2007. The Board notes that EEC made such an application on December 21, 2007.29 In Decision 2006-104, the Board approved the use of the 2006 T&C and Fee Schedule as approved in that Decision on an interim basis effective January 1, 2007 until final 2007 T&C and Fee Schedule could be fixed by the Board. Since no T&C and Fee Schedule were submitted for approval in the current Application, and due to the timing of the submission of Application No. 1552570 the Board considers that the T&C and Fee Schedule approved in Decision 2006-104 will continue to be in effect on an interim basis until the Board approves T&C and Fee Schedule on a final basis for 2007 and 2008. Audit

Section 22 of the Terms of Settlement includes a number of steps to be followed if any party requests an audit to be performed in respect of EEC’s compliance with the Terms of Settlement. The Board considers that an audit provision is beneficial for the protection of the interests of customers and therefore it is reasonable and in the public interest.

29 Application No. 1552570 – ENMAX Energy Corporation Application for Approval of EEC’s Regulated Rate

Option Amended Terms and Conditions and Price Schedule (submitted December 21, 2007)


Outstanding Directives from Decision 2006-104

In Decision 2006-104, the Board included directives to be addressed by EEC in its next RROT non-energy revenue requirement application. On page 10 of the Application, EEC indicated the following:

Finally, the parties have agreed that no later than 15 days after approval of the Terms of Settlement, EEC will file with the EUB responses to the directives given by the EUB in Decision 2006-104.

The Board was concerned that some of these directives may have had an impact on the revenue requirements for 2007 or 2008 and that these potential impacts were not addressed in the Settlement. However, in response to BR-EEC-013, EEC confirmed that there will be no adjustments to the 2007 or 2008 revenue requirements as a result of the responses to these directives. The Board is satisfied with this response. Wording and Formula Changes

As a result of its review of the Terms of Settlement, the EUB asked some IRs of EEC in which certain wording and a formula included in the Terms of Settlement were questioned. EEC provided the formula and wording changes in its response to the applicable IRs. The customer representatives were also given the opportunity to respond to the formula and wording changes. The UCA and PICA agreed with all the changes. The CCA agreed with all the changes except one. With regard to the term “Forecast 2008 Calgary CPI” being revised to “Forecast 2008 CPI” throughout the entire Terms of Settlement, the CCA submitted that with respect to Section 9 of the document, it was appropriate to modify the title but the text of that Section should remain unchanged. The CCA agreed that it was appropriate to make the change in the remaining relevant Sections of the document. The Board considers that the formula and wording changes provided by EEC, with the exception as noted above by the CCA, should be applied to the Terms of Settlement. From EEC’s IR responses, as indicated in the following Table, the Board has compiled the following adjustments to the Terms of Settlement:30 Table 4. EUB Approved Changes to the Terms of Settlement

Section Reference Wording as Filed Revised Wording Reference 6(a)(i) – Determination of Forecast 2008 B&CC Costs

$54.78*X*Y

$54.78*(1+X)*Y

BR-EEC-003

Entire Document Forecast 2007Calgary CPI Forecast 2007 CPI BR-EEC-004

Entire Document31 Forecast 2008 Calgary CPI Forecast 2008 CPI BR-EEC-004

22(d) – Audit 2009 2008 BR-EEC-008

Schedule A – Page 21 Definition entitled “2007 B&CC

“2007 B&CC Cost Adjustment

“2008 B&CC Cost Adjustment Trigger

30 Even though the Board previously in this Order addressed the error in the formula for the 2008 B&CC costs, it

has been included here for completeness and ease of reference. 31 This change has not been applied to the text in Section 9 of the Terms of Settlement.


Cost Adjustment Trigger Amount” Trigger Amount” Amount” BR-EEC-010

These changes are reflected in the Terms of Settlement attached to this Order. Variance Explanations Comparing to 2006 Actual Costs

Sections 6(c)(ii), 6(c)(iii), 7(b)(ii) and 7(b)(iii) of the Terms of Settlement refer to variance explanations that would include the 2006 actual amounts for other costs as well as B&CC costs. The EUB requested that EEC provide the 2006 actual amounts that would be used for comparison to the 2007 and 2008 actual amounts. EEC provided these 2006 figures in the responses to BR-EEC-005 and BR-EEC-015. The 2006 actual amounts provided by EEC were referred to as “2006 actual adjusted” amounts. EEC indicated in the response to BR-EEC-014 that the 2006 actual adjusted figures referred to 2006 costs adjusted for items that were disallowed or would change due to new circumstances. None of the Consultation Parties submitted any objection to EEC’s response to BR-EEC-005 and BR-EEC-015. Therefore, the Board accepts the 2006 actual adjusted figures as provided in these responses as being the 2006 actual amounts for which comparisons will be made to the 2007 and 2008 actual amounts in accordance with the sections of the Terms of Settlement outlined in the preceding paragraph. Calgary CPI

In its response to BR-EEC-009, EEC provided a website reference as well as a hard copy example of where the Calgary CPI figures for 2007 and 2008 referenced in the Terms of Settlement will be sourced. None of the Consultation Parties submitted any objection to EEC’s response to this IR. Therefore, the Board accepts this information as submitted and considers that having this information on the record of this proceeding will help to avoid any disputes about the source of the Calgary CPI information. Allocations to Rate Classes

In its response to BR-EEC-011, EEC indicated that it had agreed to use the same allocation methodology approved in Decision 2006-104 with respect to the allocation of the revenue requirements to the two rate classes. None of the Consultation Parties submitted any objection to EEC’s response to this IR. Therefore, the Board accepts this information as submitted. The Board has reviewed the allocation percentages and calculations shown on Schedule B of the Terms of Settlement and considers that the resulting revenue requirements for the residential and commercial rate classes are appropriate. Implementation of Rates

On page 11 of the Application, EEC indicated that it proposed to implement the new 2007 rates effective October 1, 2007. EEC also indicated that it will file an application for a rate rider to true up interim to final rates. The Board understands that EEC will not file its 2008 interim rate application until sometime in the first quarter of 2008. Given the date of this Order, the Board does not consider it efficient to implement 2007 final rates for the remainder of 2007 and subsequently implement interim 2008 rates early in 2008. Two rate changes in such a short period of time could be confusing for customers. Therefore, the Board considers it reasonable and in the public interest for EEC to remain on interim rates for the


remainder of 2007 (such interim rates were approved as indicated on page 39 of Decision 2006-104) and into 2008, until such a time as the 2008 interim rate application is approved by the Board. Conclusion

The Board is satisfied that the NSP was fair and achieved a unanimous Settlement that is not patently contrary to the public interest and will result in just and reasonable rates. Therefore, the Board will approve the Terms of Settlement as attached in Appendix 1 to this Order, which reflect the minor amendments set out in Table 4 of this Order. 3 ORDER

IT IS HEREBY ORDERED THAT: (1) The Terms of Settlement attached as Appendix 1 to this Order are hereby approved.

(2) ENMAX Energy Corporation’s Regulated Rate Tariff non-energy revenue requirement for 2007 of $23.434 million, included as Schedule B in the attached Appendix 1 to this Order, is hereby approved.

(3) The 2007 interim rates approved in Decision 2006-104 continue in effect on an interim basis for 2007 and 2008 as set out in the rate schedules in Appendix 2 to this Order.

(4) The 2007 interim Terms and Conditions and Fee Schedule approved in Decision 2006-104 will remain in effect as of January 1, 2008 on an interim basis. These Terms and Conditions and Fee Schedule are as set out in Appendix 3 to this Order.

END OF DOCUMENT

ENMAX Energy Corporation Appendix 1 – Terms of Settlement 2007-2008 Non-Energy RRO Negotiated Settlement Agreement Page 1 of 26

EUB Order U2007-368

TERMS OF SETTLEMENT ENMAX ENERGY CORPORATION

2007—2008 REGULATED RATE OPTION TARIFF (NON-ENERGY)

THESE TERMS OF SETTLEMENT for the negotiated settlement of the Regulated Rate Option Tariff are made and entered into as of August 14, 2007,

AMONG:

ENMAX ENERGY CORPORATION, a corporation incorporated under the laws of Alberta (“EEC”)

and

CONSUMERS’ COALITION OF ALBERTA (“CCA”), comprised of the Consumers’ Association of Canada (Alberta) and the Alberta Council on Aging,

and

OFFICE OF THE UTILITIES CONSUMER ADVOCATE, established as part of Service Alberta by Order in Council 433/2003 (the “UCA”),

and

PUBLIC INSTITUTIONAL CONSUMERS OF ALBERTA, a partnership of the Provincial Health Authorities of Alberta, Alberta’s Colleges and Technical Institutes and the Alberta School Boards Association (“PICA”),

WHEREAS:

(a) ENMAX Power Corporation (“EPC”) is responsible under the Electric Utilities Act (the “EUA”) and the Regulated Rate Option Regulation (the “Regulation”) for making available to Eligible Customers the option of being supplied Electricity Services in accordance with a Regulated Rate Option Tariff (“RROT”) instead of purchasing electricity services from a retailer;

(b) In 2001, EPC appointed EEC to provide regulated rate service in the Service Area;


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(c) In Decision 2004-065, the EUB approved EEC’s 2004 Regulated Rate Tariff non-energy costs application;

(d) In Decision 2006-001, the EUB approved EEC’s 2005 Regulated Rate Tariff non-energy costs application;

(e) In Decision 2006-104, the EUB approved EEC’s 2006 Regulated Rate Tariff non-energy costs application;

(f) in Order U2007-053, the EUB approved EEC’s request to commence a negotiated settlement process for the non-energy portion of the 2007-2010 RROT (the “NSP”);

(g) EEC and the CCA, PICA and the UCA (the CCA, PICA and the UCA will be referred to collectively in these Terms of Settlement as the “Consultation Parties”) have reached an agreement with respect to the determination of the RROT non-energy revenue requirement for the 2007 and 2008 test years;

IN CONSIDERATION of the mutual promises made in these Terms of Settlement and for other good and valuable consideration, the receipt and sufficiency of which is hereby expressly acknowledged by each of the Parties, and subject to the conditions hereinafter set out, the Parties agree as follows:

1. Definitions

Capitalized terms not otherwise defined have the meaning set out in Schedule “A” attached to these Terms of Settlement.

2. Term

These Terms of Settlement will commence upon approval by the EUB and will terminate at 11:59:59 p.m. on December 31, 2008, provided, however, that any obligation to make payment of any outstanding amounts under these Terms of Settlement, or to participate in an audit under section 22 below will survive the termination of these Terms of Settlement.

3. Accounting Practices

EEC agrees that during the Term of these Terms of Settlement, it will not make any changes to the regulatory accounting practices, principles or methods that it used to determine the 2006 non-energy revenue requirement approved by the EUB in Decision 2006-104.


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4. Responses to EUB Directives

No later than 15 days after approval of these Terms of Settlement, EEC will file with the EUB responses to the directives given by the EUB in Decision 2006-104, as summarized in Appendix 2 of that decision. Notwithstanding section 18 of these Terms of Settlement, the Consultation Parties shall be at liberty to file with the EUB written submissions regarding EEC’s responses to the directives.

5. 2007 Non-Energy Revenue Requirement

(a) The 2007 non-energy revenue requirement shall be calculated as follows:

2007 non-energy revenue requirement = A + B + C

where:

A = Forecast 2007 B&CC Costs, determined as set out in section 5(a)(i) below;

B = Forecast 2007 Other Costs, determined as set out in section 5(a)(ii) below; and

C = a non-energy margin of 6% on Forecast 2007 B&CC Costs and Forecast 2007 Other Costs.

(i) Determination of Forecast 2007 B&CC Costs

For Forecast 2007 B&CC costs, the amount to be included in the 2007 non-energy revenue requirement shall be the 2006 actual per customer B&CC costs (adjusted for transition costs to reflect Decision 2006-104) of $52.77, adjusted for Forecast 2007 CPI and Forecast 2007 Customer Count, as follows:

$52.77 x 1.038 x 293,236 = $16.062 million

(ii) Determination of Forecast 2007 Other Costs

For the Forecast 2007 Other Costs, the amounts to be included in the 2007 non-energy revenue requirement shall be the amount of $5,362,000 as approved by the EUB in Decision 2006-104, plus a $412,000 reduction to the revenue offset to reflect the elimination of application fees and a $50,000 increase to the Hearing Cost Reserve Account, multiplied by the Forecast 2007 CPI.


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(b) The 2007 non-energy revenue requirement calculated in accordance with this section, and 2007 sample rates, are set out in Schedule “B” to these Terms of Settlement.

6. 2008 Non-Energy Revenue Requirement

(a) The 2008 non-energy revenue requirement shall be calculated as follows:

2008 non-energy revenue requirement = A + B + C +/- D +/- E+/- F +/- G + H

where:

A = Forecast 2008 B&CC Costs, determined as set out in section 6(a)(i) below;

B = Forecast 2008 Other Costs, determined as set out in section 6(a)(ii) below;

C = a non-energy margin of 6% on Forecast 2008 B&CC Costs and Forecast 2008 Other Costs;

D = 2007 B&CC Cost Inflation Adjustment, determined as set out in section 6(a)(iii) below;

E = 2007 B&CC Cost Sharing Adjustment, determined as set out in section 6(a)(iv) below;

F = 2007 Other Costs Adjustment, determined as set out in section 6(a)(v) below;

G = 2007 Hearing Cost Adjustment, determined in accordance with section 6(a)(vi) below; and

H = U2007-109 Adjustment, determined as set out in section 6(a)(vi) below;.

(i) Determination of Forecast 2008 B&CC Costs

For forecast 2008 B&CC costs, the amount to be included in the 2008 non-energy revenue requirement shall be $54.78 adjusted for Forecast 2008 CPI and Forecast 2008 Customer Count, as follows:

$54.78 * (1+X) * Y

where:

X = Forecast 2008 CPI; and


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Y = Forecast 2008 Customer Count determined in accordance with section 7(a)(v).

(ii) Determination of Forecast 2008 Other Costs

For 2008 Other Costs, the amounts to be included in the 2008 non-energy revenue requirement shall be the amount determined in section 5(a)(ii) above, adjusted for Forecast 2008 CPI.

(iii) Determination of 2007 B&CC Cost Inflation Adjustment

The purpose of the 2007 B&CC Cost Adjustment is to adjust the Forecast 2007 B&CC cost (determined in accordance with section 5(a)(i)) for actual 2007 Calgary CPI, as follows:

(Forecast 2007 CPI — 2007 Calgary CPI) * 52.77 * 293,236*1.06

(iv) Determination of 2007 B&CC Cost Sharing Adjustment

The 2007 B&CC Cost Sharing Adjustment shall be determined as follows:

(A) if the Actual 2007 B&CC Cost Per Customer varies from the 2007 Adjusted B&CC Cost Per Customer by more than ±3.0%, but is equal to or less than the 2007 B&CC Cap, the 2007 B&CC Cost Sharing Adjustment shall be 50% of the variance, multiplied by the Actual 2007 Customer Count and the 6% margin; or

(B) if the Actual 2007 B&CC Cost Per Customer is greater than the 2007 B&CC Cap, the 2007 B&CC Cost Sharing Adjustment shall be the sum of:

(I) 50% of the difference between the 2007 B&CC Cap and the 2007 B&CC Cost Adjustment Trigger Amount, all multiplied by the Actual 2007 Customer Count and the 6% margin; and

(II) the 2007 B&CC Cap Adjustment, determined as set out immediately below. If the 2007 B&CC Cap Adjustment (if any) cannot be settled or determined in time for inclusion in 2008 final rates in accordance with section 6(e) below, the 2007 B&CC Cap


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Adjustment shall be added to the 2009 revenue requirement.

In the event that the Actual 2007 B&CC Cost Per Customer is greater than the 2007 B&CC Cap, EEC may, no later than April 30, 2008, submit a written request to the Consultation Parties for a 2007 B&CC Cap Adjustment under which all or part of the amount by which the Actual 2007 B&CC Cost Per Customer exceeds the 2007 B&CC Cap would be subject to the cost sharing formula set out in section 6(a)(iv)(A) above. This written request shall include supporting evidence for the request, and EEC agrees to respond to information requests submitted by the Consultation Parties in respect of the written request. If the Consultation Parties agree to EEC’s request, the 2007 B&CC Cap Adjustment shall be 50% of the amount that the Parties agree to subject to the cost sharing formula, multiplied by the Actual 2007 Customer Count and the 6% margin.

If the Consultation Parties do not agree to EEC’s request, EEC may seek EUB approval of the request for a 2007 B&CC Cap Adjustment. If the EUB approves the request, in whole or in part, the 2007 B&CC Cap Adjustment shall be 50% of the amount that the EUB approves to be subject to the cost sharing, multiplied by the Actual 2007 Customer Count and the 6% margin.

(v) Determination of 2007 Other Costs Adjustment

The purpose of the 2007 Other Costs Adjustment is to adjust the Forecast 2007 Other Costs (determined in accordance with section 5(a)(ii)) above for actual 2007 Calgary CPI, as follows:

(Forecast 2007 CPI – 2007 Calgary CPI) * $5,824,000 *1.06

(vi) 2007 Hearing Costs Adjustment

The purpose of the 2007 Hearing Costs Adjustment is to adjust the forecast hearing costs included as part of the forecast 2007 Other Costs to reflect actual 2007 hearing costs, as follows:

($374,000*(1+2007 Calgary CPI) – 2007 Approved Hearing Costs) *1.06

(vii) Determination of U2007-109 Adjustment

No later than March 15, 2008, EEC shall provide the Consultation Parties with a written statement showing any discrepancy between


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the shortfall of $631,999 for residential customers and $70,734 for commercial customers referred to in EUB Order U2007-109 and the amount collected through the rider implemented under that order, along with EEC’s proposal for dealing with the discrepancy in accordance with the EUB’s direction in Order U2007-109. If the Parties disagree with EEC’s determination, and the Parties are unable to reach an agreement within a reasonable period of time, EEC shall submit the matter to the EUB for final determination.

(b) No later than November 15, 2007, EEC will provide the Consultation Parties with a calculation of the interim 2008 non-energy revenue requirement (A+B+C, determined in accordance with section 6(a) above). EEC will file a schedule setting out the interim 2008 non-energy revenue requirement and sample rates with the EUB for information and for implementation January 1, 2008.

(c) As soon as the relevant data are available, and in any event, no later than March 15, 2008, EEC shall send the Consultation Parties a written statement setting out EEC’s calculations of adjustments D through H (as determined in accordance with section 6(a) above) and proposed final 2008 rates. This statement shall also include the following information:

(i) Actual 2007 Customer Count;

(ii) actual 2007 Other Costs by category, identifying variances from 2006 EUB approved and 2006 actual Other Costs and providing explanations for the variances; and

(iii) Actual 2007 B&CC Cost by category identifying variances from 2006 EUB approved B&CC Costs and 2006 actual B&CC Costs.

(d) No later than March 31, 2008, the Parties shall meet to review the proposed adjustments and final rates provided under section 6(c).

(e) No later than April 15, EEC shall file the proposed 2008 final rates with the EUB for implementation May 1, 2008.

7. Adjustments to 2009 Non-energy Revenue Requirement

(a) The 2009 non-energy revenue requirement shall be subject to a 2008 B&CC Cost Inflation Adjustment, a 2008 B&CC Cost Sharing Adjustment, a 2007 B&CC Cap Adjustment (if necessary), a 2008 Other Costs Adjustment and a 2008 Hearing Cost Account Adjustment, all determined as set out below:


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(i) Determination of 2008 B&CC Inflation Cost Adjustment

The purpose of the 2008 B&CC Cost Inflation Adjustment is to adjust the Forecast 2008 B&CC Cost determined in accordance with section 6(a)(i) for actual 2008 Calgary CPI, as follows (where a negative number means an increase to the 2009 revenue requirement and a positive number means a reduction to the 2009 revenue requirement):

[(1+ Forecast 2007 CPI) * (1+Forecast 2008 CPI)] – [(1+2007 Calgary CPI) *(1+2008 Calgary CPI)] *52.77 * 2008 Forecast Customer Count*1.06

(ii) Determination of 2008 B&CC Cost Sharing Adjustment

The 2008 B&CC Cost Sharing Adjustment shall be determined as follows:

(A) if the Actual 2008 B&CC Cost Per Customer varies from the 2008 Adjusted B&CC Cost Per Customer by more than ±3.0%, but is equal to or less than the 2008 B&CC Cap, the 2008 B&CC Cost Sharing Adjustment shall be 50% of the variance, multiplied by the Actual 2008 Customer Count and the 6% margin; or

(B) if the Actual 2008 B&CC Cost Per Customer is greater than the 2008 B&CC Cap, the 2008 B&CC Cost Sharing Adjustment shall be the sum of:

(I) 50% of the difference between the 2008 B&CC Cap and the 2008 B&CC Cost Adjustment Trigger Amount, all multiplied by the Actual 2008 Customer Count and the 6% margin; and

(II) the 2008 B&CC Cap Adjustment, determined as set out immediately below.

In the event that the Actual 2008 B&CC Cost Per Customer is greater than the 2008 B&CC Cap, EEC may, no later than April 30, 2009, submit a written request to the Consultation Parties for a 2008 B&CC Cap Adjustment under which all or part of the amount by which the Actual 2008 B&CC Cost Per Customer exceeds the 2008 B&CC Cap would be subject to the cost sharing formula set out in section 7(a)(ii)(A) above. This written request shall include


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supporting evidence for the request, and EEC agrees to respond to information requests submitted by the Consultation Parties in respect of the written request. If the Consultation Parties agree to EEC’s request, the 2008 B&CC Cap Adjustment shall be 50% of the amount that the Parties agree to subject to the cost sharing formula, multiplied by the Actual 2008 Customer Count and the 6% margin.

If the Consultation Parties do not agree to EEC’s request, EEC may seek EUB approval of the request for a 2008 B&CC Cap Adjustment. If the EUB approves the request, in whole or in part, the 2008 B&CC Cap Adjustment shall be 50% of the amount that the EUB approves to be subject to the cost sharing, multiplied by the Actual 2008 Customer Count and the 6% margin.

(iii) 2007 B&CC Cap Adjustment

The 2007 B&CC Cap Adjustment means the 2007 B&CC Cap Adjustment determined in accordance with section 6(a)(iv) above, unless the 2007 B&CC Cap Adjustment has already been recovered through 2008 rates.

(iv) Determination of the 2008 Other Costs Adjustment

The purpose of the 2008 Other Costs Adjustment is to adjust the Forecast 2008 Other Costs (determined in accordance with section 5(a)(ii) above) for actual 2008 Calgary CPI, as follows (where a negative number means an increase to the 2009 revenue requirement and a positive number means a reduction to the 2009 revenue requirement):

[(1+ Forecast 2007 CPI) * (1+Forecast 2008 CPI)] – [(1+2007 Calgary CPI) * (1+ 2008 Calgary CPI)] * 5,824,000*1.06

(v) Determination of 2008 Hearing Cost Adjustment

The purpose of the 2008 Hearing Costs Adjustment is to adjust the forecast hearing costs included as part of the forecast 2008 Other Costs to reflect actual 2008 hearing costs, as follows:

($374,000*(1+2007 Calgary CPI) * (1+2008 Calgary CPI) – (2008 Approved Hearing Costs + any 2007 hearing costs approved by the EUB but not included in the 2007 Hearing Cost Adjustment) *1.06


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(b) As soon as the relevant data are available, and in any event, no later than March 15, 2009, EEC shall send the Consultation Parties a written statement setting out EEC’s calculations of adjustments determined in accordance with section 7(a) above and proposed 2009 final rate adjustments (which may be subject to future adjustment under section (a)(ii)(B)(II) above). This statement shall also include the following information:

(i) Actual 2008 Customer Count;

(ii) actual 2008 Other Costs by category, identifying variances from 2006 EUB approved, 2006 actual and 2007 actual Other Costs, and providing explanations for the variances; and

(iii) Actual 2008 B&CC Costs by category, identifying variances from 2006 EUB approved, 2006 actual and 2007 actual B&CC Costs, and providing explanations for the variances.

(c) No later than March 31, 2009, the Parties shall meet to review the proposed adjustments and final rates provided under 7(b).

(d) No later than April 16, EEC shall file the proposed 2009 final rate adjustments with the EUB for implementation May 1, 2009.

8. Forecast 2008 Customer Count

(a) No later than November 15, 2007, EEC will provide to the Consultation Parties a written customer count forecast for 2008. This forecast shall be determined using the same method used by EEC in Application No. 1500728 to determine the forecast customer count approved by the EUB in Order U2007-109 and will be used to determine the interim 2008 non-energy revenue requirement under section 6(b) above for implementation January 1, 2008.

(b) If the Consultation Parties have concerns regarding the Forecast 2008 Customer Count, EEC and the Consultation Parties shall attempt to resolve these concerns. If the Parties are unable to resolve these concerns by January 31, 2008, EEC shall file the Forecast 2008 Customer Count with the EUB for approval, and any Party may make written submissions to the EUB regarding the Forecast 2008 Customer Count.

(c) If, section 8(b) above, the Parties agree to or the EUB approves a different 2008 Forecast Customer Count from the forecast proposed by EEC in


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section 8(a) above, the interim 2008 non-energy revenue requirement will be trued up accordingly at the time the adjustments referred to in section 6(c) above are made.

9. Forecast 2008 CPI

EEC shall determine a Forecast 2008 Calgary CPI for the purposes of determining the Forecast 2008 B&CC Costs and the Forecast 2008 Other Costs.

10. Income Tax

The Parties acknowledge that as of January 1, 2007, EEC’s RRO non-energy revenue became subject to the provisions of the Payment in Lieu of Tax Regulation. The Parties further acknowledge that at the present time, it is not known whether EEC will be liable to make any payments under the Payment in Lieu of Tax Regulation in respect of its 2007 or 2008 RRO non-energy taxable income. Therefore, the Parties agree that if EEC becomes liable to make such payments, it may apply to recover those payments as part of its 2009 non-energy revenue requirement. If EEC makes such an application, the Consultation Parties shall have the right to make submissions regarding the assumptions, calculation and methods used for determining income taxes, but they may not argue that EEC ought to have recovered those payments under its 2007 or 2008 non-energy revenue requirement.

11. Capital Expenditures

No later than March 15, 2008, EEC shall provide to the Consultation Parties information regarding 2007 capital expenditures in excess of $500,000 in a spreadsheet in the form and containing the information set out in Schedule “C” to these Terms of Settlement. For the purposes of this Agreement, the Parties agree that components of larger projects are to be listed together for the purposes of determining the $500,000 threshold.

12. Terms and Conditions

EEC and the Consultation Parties shall meet to consider amendments to EEC’s RROT terms and conditions and fee schedule. If the Parties are unable to agree upon amendments to the terms and conditions and fee schedule by September 30, 2007, EEC may file amended terms and conditions and fee schedule with the EUB for approval, in which case the Consultation Parties shall be at liberty to file with the EUB written submissions regarding EEC’s amended terms and conditions and fee schedule,

13. Hearing Cost Reserve Account

The Hearing Cost Reserve Account shall be continued.


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14. Provision of Directive 014 Information to the Consultation Parties

EEC will provide the Consultation Parties with a copy of the Report of Finance and Operations that EEC is required to file in accordance with EUB Directive 014 as soon as practical after that report is in final form and ready for filing.

15. Representations and Warranties

(a) The Consultation Parties each represent to EEC that:

(i) they are duly organized, validly existing and in good standing under the laws of Alberta;

(ii) they have not withheld any relevant information; and

(iii) all information provided during the negotiated settlement process was true and accurate, to the best of the Consultation Parties’ knowledge.

(b) EEC represents and warrants to the Consultation Parties that:

(i) it is duly organized, validly existing and in good standing under the laws of Alberta; and

(ii) it has not withheld any relevant information; and

(iii) all information provided during the negotiated settlement process was true and accurate, to the best of EEC’s knowledge.

16. Amendment

In the event of a change in law that impacts these Terms of Settlement, any Party may propose an amendment to these Terms of Settlement. EEC and the Consultation Parties agree that the financial impact of any change in law will be flowed through to Eligible Customers, unless the Parties agree that the impact of the change in law is not material. Any dispute among the Parties regarding whether a change in law has occurred or whether there is a financial impact resulting from a change in law shall be submitted to the EUB for resolution.

17. Review

The Consultation Parties agree that they shall not seek to review or reopen these Terms of Settlement (except by way of a proposed amendment in accordance with section 16), except in the event of Material Misconduct, in which case any Party may


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bring an application to the EUB. In the event of an application under this section, the EUB shall determine whether there has been Material Misconduct, and if there has been Material Misconduct, whether these Terms of Settlement should be varied or set aside.

18. Support of Terms of Settlement

The Consultation Parties agree that they will support the application by EEC to the EUB for approval of these Terms of Settlement.

19. EUB Approval

The Parties acknowledge that these Terms of Settlement are contingent upon approval by the EUB under the EUA. If the EUB rejects these Terms of Settlement in whole or in part, or attaches any conditions to the approval of these Terms of Settlement that materially impact the Terms of Settlement, unless all Parties agree otherwise in writing, these Terms of Settlement will be of no force and effect and all Parties will be released from the terms of these Terms of Settlement.

20. Costs

EEC will pay, on an interim refundable basis, the costs incurred by the CCA and PICA in negotiating matters related to and encompassed in these Terms of Settlement upon receipt of an invoice by those Parties and provided that the Party indicates in writing that its costs have been reasonable incurred and that the cost claim complies with the EUB’s Guidelines for Utility Cost Claims. The invoice must be received by EEC not later than 30 days after these Terms of Settlement have been submitted to the EUB for approval. The CCA and PICA will each be solely responsible for obtaining EUB approval of its costs in respect of the costs in respect of the negotiation and approval of these Terms of Settlement in accordance with the practice of the EUB. This provision regarding cost recovery specifically contemplates that the EUB, in its review of the costs claim of a Party, may address whether the costs were appropriate and “made a contribution to the process,” as required under the EUB’s cost recovery guidelines. If the EUB does not approve all or a portion of the costs paid by EEC to a Party under this provision, that Party will pay the disallowed amount, including GST to EEC within the later of 30 days of the EUB’s cost order, or 30 days after the conclusion of any review or appeal of that order.

The Parties acknowledge and agree that payment of costs by EEC on an interim refundable basis as contemplated under this provision is not intended to influence or bind the EUB in the exercise of its authority with respect to costs under its cost recovery guidelines. EEC will include the costs approved by the EUB for each Party in its hearing cost reserve account.


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21. Without Prejudice

These Terms of Settlement are agreed to without prejudice to the position of the Parties in subsequent negotiations and/or regulatory proceedings. Specifically, the Parties acknowledge that these Terms of Settlement were agreed to against the unique backdrop of the provisions of the Regulated Rate Option Regulation and EPC’s Service Area, and were compromises between the Parties to achieve a settlement regarding the RROT for the 2007 and 2008 test years. The Parties agree that these Terms and Settlement have no precedential value in future proceedings and/or negotiations with EEC or any other regulated rate provider.

22. Audit

(a) Any of the Parties (the “Requesting Party” or the “Requesting Parties”) may elect, on 30 days’ written notice to EEC, to select an audit firm, subject to sections 22(b), (c) and (d) below, to perform an audit in respect of EEC’s compliance with the specific terms of these Terms of Settlement for the applicable year, as long as notice is received within 120 after the report on finance and operations in respect of 2007 or 2008, as the case may be, is provided by EEC.

(b) If more than one Requesting Party elects within the time permitted under section 22(a) above to undertake an audit, the Requesting Parties will jointly undertake a single audit rather than separate audits. Subject to section 22(c) below, the audit will be performed at the expense of the Requesting Party or the Requesting Parties electing to have the audit performed (excluding any reasonable internal or external costs incurred by EEC). The audit will be conducted at reasonable times and in a manner so as to minimize the disruption of EEC’s business.

(c) Upon application by a Requesting Party, the EUB may direct that the costs of an audit be borne by all Eligible Customers, provided that the EUB is satisfied that there are reasonable grounds for requesting an audit.

(d) Any audit undertaken under this provision will be performed by a mutually acceptable national audit firm and failing agreement, the EUB shall decide. The audit firm will be required to enter into a confidentiality agreement in a form reasonably acceptable to EEC prior to undertaking the audit. EEC will retain all financial records pertaining to the 2007 and 2008 revenue requirements and 2007 and 2008 financial results. EEC will provide all reasonable cooperation, including, subject to clause 22(g), access to its source data as necessary for the effective and efficient completion of the audit.


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(e) The Requesting Party or Requesting Parties electing to have an audit undertaken under the provision will ensure that an audit report is prepared by the members of the audit firm who complete the audit and will provide EEC with a copy of the audit report. A Requesting Party may provide a copy of the audit report to the EUB.

(f) The Requesting Party or Requesting Parties and EEC will determine mutually acceptable terms of reference for the audit, which terms of reference will be structured so as to test EEC’s compliance with these Terms of Settlement and generally in the form of a special purpose report pursuant to the CICA Handbook. In the event that the Requesting Party or Requesting Parties and EEC cannot agree on terms of reference within the 30 days referred to in section 22(a) above, the EUB shall set the terms of reference.

(g) An audit undertaken in accordance with this provision is restricted to the Calgary RRO, and the auditors shall not have access to information that has not been available in previous non-energy RRO applications, unless first agreeing that such information is confidential and shall not be disclosed. Further, in reporting to the Requesting Party or Requesting Parties, the auditor shall not disclose any confidential information and shall limit its report related to confidential information to a simple statement that the auditor believes that there has been a breach of a particular provision of these Terms of Settlement, or that the auditor believes that there has not been a breach of a these Terms of Settlement. For greater certainty, the auditors shall not have access to ABSU total invoiced costs (which include costs associated with unregulated business), the billing and customer care allocation model developed by KPMG, or any data or information related to EEC’s unregulated business, unless it is related to the terms of reference of the audit determined in accordance with section 22(f) above, and unless first agreeing that such information is confidential and shall not be disclosed. Under no circumstances will the auditor be granted access to the ABSU Contract.

(h) Should the auditor conclude that EEC has breached a provision of these Terms of Settlement, EEC shall be provided with particulars of the alleged breach and shall be given a reasonable opportunity to respond to the alleged breach. In responding to an alleged breach, EEC may allow the disclosure of confidential information to the Requesting Party or the Requesting Parties. If EEC chooses not to respond to an alleged breach, or if the Requesting Party or Requesting Parties are not satisfied with EEC’s response to an alleged breach, the Requesting Party or Requesting Parties


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may elect, under section 22(e) above, to file the audit report with the EUB and request that the EUB investigate the alleged breach and determine a remedy if the EUB concludes that there has been a breach of these Terms of Settlement.

23. Miscellaneous

(a) Where a term is defined in these Terms of Settlement, a capitalized derivative of that term will have a corresponding meaning unless the context otherwise requires.

(b) In these Terms of Settlement, references to:

(i) meetings include meetings in person and by teleconference;

(ii) sections are to sections in these Terms of Settlement, unless otherwise stated;

(iii) schedules are to schedules attached to these Terms of Settlement, each of which is incorporated and made a part of these Terms of Settlement for all purposes as if set out in full in these Terms of Settlement; and

(iv) “including” means “including, without limitation,” and “includes” and other derivates will have corresponding meanings.

(c) The division of these Terms of Settlement into sections and the provision of headings in these Terms of Settlement are for convenience of reference only and will not affect the construction or the interpretation of these Terms of Settlement.

(d) In these Terms of Settlement, words importing the singular will include the plural and vice versa.

(e) Any reference to a statute or regulation is a reference to it as re-enacted, varied, amended, modified, supplemented or replaced from time to time.

(f) All amounts payable under these Terms of Settlement are payable in Canadian dollars and references in these Terms of Settlement to monetary amounts are references to lawful currency of Canada.

(g) These Terms of Settlement and the Schedules attached to or to be attached to these Terms of Settlement contain the entire understanding and agreement of the Parties and will form a single integrated agreement


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between the Parties. Subject to section 23(h) below, nether EEC nor the Consultation Parties will assign these Terms of Settlement without the prior written consent of the other Parties; provided that such consent will not be unreasonably withheld. These Terms of Settlement may be modified, altered or amended only by an agreement in writing, signed by the Parties.

(h) In the event that EEC ceases to be regulated rate provider for EPC’s Service Area, EEC shall assign these Terms and Conditions to the new regulated rate provider for EPC’s Service Area;

(i) Any notice or other communication from one Party to the other Parties required or permitted to be given or made under these Terms of Settlement will be in writing and will be sufficiently given or made if delivered during normal business hours on a Business Day and left at the recipient’s address for notice set out below, or if transmitted to the recipient by facsimile or other means of electronic communication capable of confirming receipt; and:

if to EEC, addressed to:

ENMAX Energy Corporation 141 – 50th Avenue S.E. Calgary, Alberta T2G 4S7

Attention: Al Buchignani Facsimile: (403) 514-2657 E-mail: [email protected]

if to CCA addressed to:

Consumers’ Coalition of Alberta c/o Wachowich & Company 555 – 10310 Jasper Avenue Edmonton, Alberta T5J 2W4

Attention: James A. Wachowich Facsimile: (780) 425-4795 E-mail: [email protected]


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if to PICA, addressed to:

Public Institutional Consumers of Alberta c/o 530 Carse Lane Edmonton, Alberta T6R 2L7

Attention: Raj Retnanandan Facsimile: (780) 433-3420 E-mail: [email protected]

if to UCA, addressed to:

Office of the Utilities Consumer Advocate TD Tower 1701, 10088 – 102 Avenue Edmonton, AB T5J 2Z1

Attention: Manager, Regulatory Affairs: Ron Henderson Facsimile: (780) 644-5129 E-mail: [email protected]

(j) Any notice or other communication given or made in the above manner will be deemed to have been given or made and to have been received on the day of delivery or transmission, as the case may be, if delivered or transmitted during the normal business hours of the recipient on a Business Day and, if not, on the next succeeding Business Day. Any Party may change the address or facsimile number to which such communications are to be directed to it by giving written notice of that change to the other Parties in accordance with this section.

(k) No waiver of any provision of these Terms of Settlement will be valid or enforceable unless in writing and signed by the Party against whom enforcement of the waiver is sought. The waiver of any provision of these Terms of Settlement, at any time, by any Party, will not constitute a waiver of future compliance with that provision or a waiver of compliance with any other provision of these Terms of Settlement.

(l) These Terms of Settlement and all disputes arising in connection with these Terms of Settlement will be subject to, governed by, and construed in accordance with the laws of the Province of Alberta including the laws of Canada that are applicable therein.

(m) Subject to section 19 and except as otherwise set out in these Terms of Settlement, in the event that any of the provisions of these Terms of


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Settlement are held by a court of competent jurisdiction to be invalid, void or otherwise unenforceable, all other provisions of these Terms of Settlement will remain enforceable to the fullest extent permitted by law, unless such finding materially impairs the economic benefit or protections to be derived by a Party from the transactions contemplated hereby taken as a whole. However, if any provision of these Terms of Settlement is found to be invalid or unenforceable by the EUB or a court of competent jurisdiction, the Parties agree, insofar as they are able, to meet to negotiate a replacement provision intended to preserve the respective benefits and obligations of the Parties provided for under these Terms of Settlement.

(n) These Terms of Settlement may be executed by facsimile transmission and acknowledged in multiple counterparts and by different Parties in separate counterparts, each of which will be an original and all of which will be and constitute one and the same instrument.

(o) Time will be of the essence in respect of these Terms of Settlement.

(p) These Terms of Settlement will enure to the benefit of and be binding upon the Parties and their respective successors and permitted assigns.

IN WITNESS WHEREOF, the Parties have duly executed these Terms of Settlement as of the date set out above.

ENMAX ENERGY CORPORATION CONSUMERS’ COALITION OF ALBERTA

Per: Per:

Name: Title:

Name: Title:

OFFICE OF THE UTILITIES CONSUMER ADVOCATE

PUBLIC INSTITUTIONAL CONSUMERS OF ALBERTA

Per: Per

Name: Title:

Name: Title:


EUB Order U2007-368

SCHEDULE “A”

DEFINITIONS

The following terms have the meanings set out below:

“2006 Other Costs” means the amount approved by the EUB in Decision 2006-104 in respect of Other Costs, plus a $412,000 reduction to the revenue offset to reflect the elimination of application fees and a $50,000 increase to the Hearing Cost Reserve Account;

“2007 Adjusted B&CC Cost Per Customer” means the Forecast 2007 B&CC Costs adjusted by the 2007 B&CC Cost Inflation Adjustment, divided by 293,236;

“2007 Approved Hearing Costs” means the 2007 non-energy RRO hearing costs approved by the EUB;

“2007 B&CC Cap” means $58.07 per customer;

“2007 B&CC Cap Adjustment” means the adjustment determined in accordance with section 6(a)(iv) of these Terms of Settlement;

“2007 B&CC Cost Inflation Adjustment” means the adjustment determined in accordance with section 6(a)(iii) of these Terms of Settlement;

“2007 B&CC Cost Sharing Adjustment” means the adjustment determined in accordance with section 6(a)(iv) of these Terms of Settlement;

“2007 B&CC Cost Adjustment Trigger Amount” means the 2007 Adjusted B&CC Cost Per Customer * 1.03;

“2007 Calgary CPI” means the difference between the average annual “all items” Consumer Price Index published by Statistics Canada for the city of Calgary for 2007 and 2006 (base year 2002), expressed as a percentage;

“2007 Hearing Costs Adjustment” means the adjustment determined in accordance with section 6(a)(vi) of these Terms of Settlement;

“2007 Other Costs Adjustment” means the adjustment determined in accordance with section 6(a)(v) of these Terms of Settlement;


EUB Order U2007-368

“2008 Adjusted B&CC Cost Per Customer” means the Forecast 2008 B&CC Costs adjusted by the 2008 B&CC Cost Inflation Adjustment, divided by the Forecast 2008 Customer Count determined in accordance with section 8 of these Terms of Settlement;

“2008 Approved Hearing Costs” means the 2008 non-energy RRO hearing costs approved by the EUB;

“2008 B&CC Cap” means $60.28 per customer;

“2008 B&CC Cost Inflation Adjustment” means the adjustment determined in accordance with section 7(a)(i) of these Terms of Settlement;

“2008 B&CC Cost Sharing Adjustment” means the adjustment determined in accordance with section 7(a)(ii) of these Terms of Settlement;

“2008 B&CC Cost Adjustment Trigger Amount” means the 2008 Adjusted B&CC Cost Per Customer * 1.03;

“2008 Calgary CPI” means the difference between the average annual “all items” Consumer Price Index published by Statistics Canada for the city of Calgary for 2008 and 2007 (base year 2002), expressed as a percentage;

“2008 Hearing Costs Adjustment” means the adjustment determined in accordance with section 7(a)(v) of these Terms of Settlement;

“2008 Other Costs Adjustment” means the adjustment determined in accordance with section 7(a)(iv) of these Terms of Settlement;

“ABSU” means Accenture Business Services for Utilities Inc.;

“ABSU Contract” means the agreement dated September 26, 2006 between ABSU and ENMAX Encompass Inc. under which ABSU provides billing and customer care services.

“Actual 2007 B&CC Cost” means the actual B&CC costs incurred by EEC for 2007;

“Actual 2007 B&CC Cost Per Customer” means the Actual 2007 B&CC Cost divided by the Actual 2007 Customer Count;

“Actual 2007 Customer Count” means the actual annual average RRO customer count for 2007, calculated in the same manner as the average number of customers that was approved by the EUB in Order U2007-109;


EUB Order U2007-368

“Actual 2008 B&CC Cost” means the actual B&CC costs incurred by EEC for 2008;

“Actual 2008 B&CC Cost Per Customer” means the Actual 2008 B&CC Cost divided by the Actual 2008 Customer Count;

“Actual 2008 Customer Count” means the actual annual average RRO customer count for 2008, calculated in the same manner as the average number of customers that was approved by the EUB in Order U2007-109;

“Business Day” means a calendar day other than a Saturday, Sunday or statutory holiday in the Province of Alberta;

“B&CC Costs” means billing and customer care costs, including the following categories of costs, as set out in Table 4.5 of Application No. 1455154: ABSU Costs, ENMAX internal billing costs, ENMAX bank charges, ADS fee for CIS, EEI depreciation and transition costs;

“Calgary CPI” means, for any year, the average annual “all items” Consumer Price Index published by Statistics Canada for the city of Calgary for that year, expressed as a percentage;

“CCA” means the Consumers’ Coalition of Alberta;

“Consultation Parties” means the CCA, PICA and the UCA;

“EEC” means ENMAX Energy Corporation;

“Eligible Customer” has the meaning set out in the Regulated Rate Option Regulation, AR 262/2005, or its replacement;

“EPC” means ENMAX Power Corporation;

“EUA” means the Electric Utilities Act, S.A. 2003, c. E-5.1;

“EUB” means the Alberta Energy and Utilities Board or its successor;

“Forecast 2007 B&CC Costs” means the costs determined in accordance with section 5(a)(i) of these Terms of Settlement;

“Forecast 2007 CPI” means 3.8%;

“Forecast 2007 Customer Count” means 92% of the actual 2006 customer count of 318,735, or 293,296;


EUB Order U2007-368

“Forecast 2007 Other Costs” means the Other Costs determined in accordance with section 5(a)(ii) of these Terms of Settlement;

“Forecast 2008 B&CC Costs” means the costs determined in accordance with section 6(a)(i) of these Terms of Settlement;

“Forecast 2008 CPI” means the forecast determined by EEC in accordance with section 9 of these Terms of Settlement;

“Forecast 2008 Customer Count” means the customer count determined in accordance with section 8 of these Terms of Settlement;

“Forecast 2008 Other Costs” means the Other Costs determined in accordance with section 6(a)(ii) of these Terms of Settlement;

“Hearing Cost Reserve Account” means the hearing cost reserve account first approved by the EUB in Decision 2003-086;

“Material Misconduct” means the provision by EEC of false information, information that contains a material error, information that, in the circumstances, a reasonable person would consider misleading, or the failure to disclose material information;

“Other Costs” means all categories of non-energy related costs that make up the non-energy revenue requirement, including depreciation and revenue offsets, but excluding B&CC costs;

“Parties” means the parties to these Terms of Settlement;

“Payment in Lieu of Tax Regulation” means the Payment in Lieu of Tax Regulation, AR 112/2003 as amended, or any replacement regulation;

“PICA” means the Public Institutional Consumers of Alberta;

“RRO” means regulated rate option;

“Regulated Rate Option Regulation” means the Regulated Rate Option Regulation, AR 262/2005, as amended, or any replacement regulation;

“RROT” means a regulated rate option tariff as contemplated under Section 103 of the EUA and the Regulated Rate Option Regulation;

“Service Area” means the area served by the EPC electric distribution system in the Province of Alberta;


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“Term” has the meaning set out in Section 2 of the Terms of Settlement;

“Terms and Conditions” means the terms and conditions of service for the EEC RROT, as approved by the EUB from time to time;

“Terms of Settlement” means these Terms of Settlement dated August 14, 2007 between EEC and the Consultation Parties; and

“U2007-109 Adjustment” means the amount determined in accordance with section 6(a)(vii) of these Terms of Settlement;

“UCA” means the Office of the Utilities Consumer Advocate, established by Order In Council 433/2003.


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SCHEDULE “B”

ENMAX ENERGY CORPORATION 2007—2008 REGULATED RATE OPTION TARIFF (NON-ENERGY)

2007 NON-ENERGY REVENUE REQUIREMENT AND SAMPLE RATES

EEC 2007 Administration charges for Residential and Commercial customers.

2007 Revenue Requirement

Allocation Residential

Allocation Commercial Residential Commercial

($ millions) (%) (%) ($

millions) ($ millions) Total Billing & Customer Care 16,062 94.70 5.30 15,211 851 2007 Forecast customer count 293,236 277,695 15,542 B&CC/customer ($/year) 54.78 Other Costs Shared Services 3,050 94.70 5.30 2,888 162 Operational Costs 1,877 94.70 5.30 1,777 99 Working Capital (20) 10.53 89.47 (2) (18) Hearing Costs 388 94.70 5.30 368 21 Bad Debt 1,520 88.52 11.48 1,345 174 Depreciation 1,781 94.70 5.30 1,687 94 Revenue Offset (2,550) 90.52 9.48 (2,309) (242) Total Other costs 6,045 5,754 291 Total Revenue Requirement 22,107 20,965 1,142 Margin @ 6% 1,326 1,258 69 Total Revenue Requirement 23,434 22,223 1,211 Residential Commercial Rate Calculations $/year 80.03 77.91 days/year 365 365 $/day 0.2192 0.2135


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SCHEDULE “C”

ENMAX ENERGY CORPORATION 2007—2008 REGULATED RATE OPTION TARIFF (NON-ENERGY)

CAPITAL EXPENDITURE INFORMATION FORMAT

Description

OpeningCWIP Balance

Cap Expend

Cap Adds

Closing CWIP Balance

ENMAX Energy Enterprise Software-Data Warehouse Enterprise Software-Settlement Office Furniture Computer Hardware Computer Software Total ENMAX Encompass Enterprise Software-Billing Enterprise Software-Customer Care Enterprise Software-Marketing Interface Computer Software Computer Hardware Total ENMAX Corporate Enterprise Software Computer Software Computer Hardware Office Furniture Trade Fixtures (Building/Signs) Total Total RRT Capital Assets

ENMAX Energy Corporation Appendix 2 – Board Approved Interim 2008 Rate Schedules 2007-2008 Non-Energy RRO Negotiated Settlement Agreement Page 1 of 5

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Effective: January 1, 2008

2008 REGULATED RATE OPTION TARIFF The rate schedules are for the provision of electricity services in accordance with the Regulated Rate Option Regulation (AR 262/2005) and the Electric Utilities Act, S.A. 2003, c. E-5.1. Rate Schedules

Rate Description Residential Regulated Rate Option Tariff Small Commercial Regulated Rate Option Tariff Medium Commercial Regulated Rate Option Tariff Large Commercial Regulated Rate Option Tariff

Local Access Fee (“LAF”) The LAF is a surcharge imposed by the City of Calgary and is not approved by the Alberta Energy and Utilities Board. The LAF is applicable to all services located within the City of Calgary.

LAF 11.11% of the total revenue from Distribution Tariff rate charges in the billing period

Plus

11.11% of Energy Revenue Where,

Energy Revenue is the Residential Rate R100 Energy Charge times Energy Delivered.


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Regulated Rate Option Tariff

Residential This rate schedule is for the provision of electricity services in accordance with the Regulated Rate Option Regulation (AR 262/2005) and the Electric Utilities Act, S.A. 2003, c. E-5.1. Applicability 1. This rate applies to “rate classification customers” as defined by the Regulated Rate

Option Regulation (AR 262/2005).

2. This rate applies to all residential customers which obtain D100 service pursuant to the ENMAX Power Corporation Distribution Tariff.

Rate Energy Charge Changes Monthly ($/kWh) Administration Charge $0.1956 per day System Access Service Charge As per Distribution Tariff Distribution Assess Service Charge As per Distribution Tariff

Local Access Fee (LAF) The LAF is a surcharge imposed by the City of Calgary and is not approved by the Alberta Energy and Utilities Board. The LAF is applicable to all services located within the City of Calgary.

Billing Period Monthly Terms and Conditions All services provided under this rate are subject to ENMAX Energy Corporation Terms and Conditions for the Regulated Rate Option Tariff.


EUB Order U2007-368



Small Commercial This rate schedule is for the provision of electricity services in accordance with the Regulated Rate Option Regulation (AR 262/2005) and the Electric Utilities Act, S.A. 2003, c. E-5.1. Applicability 1. Commercial Customers are eligible for this rate if a reasonable forecast of the customer’s

annual consumption of electric energy at a site is less than 250 MWh.

2. This rate applies to all commercial customers which obtain D200 service pursuant to the ENMAX Power Corporation Distribution Tariff.

Rate Energy Charge Changes Monthly ($/kWh) Administration Charge $0.1870 per day System Access Service Charge As per Distribution Tariff Distribution Access Service Charge As per Distribution Tariff Local Access Fee (LAF) The LAF is a surcharge imposed by the City of Calgary and is not approved by the Alberta Energy and Utilities Board. The LAF is applicable to all services located within the City of Calgary.

Billing Period Monthly

Terms and Conditions All services provided under this rate are subject to ENMAX Energy Corporation Terms and Conditions for the Regulated Rate Option Tariff.


EUB Order U2007-368



Medium Commercial This rate schedule is for the provision of electricity services in accordance with the Regulated Rate Option Regulation (AR 262/2005) and the Electric Utilities Act, S.A. 2003, c. E-5.1. Applicability 1. Commercial Customers are eligible for this rate if a reasonable forecast of the customer’s


2. This rate applies to all commercial customers which obtain D300 service pursuant to the ENMAX Power Corporation Distribution Tariff.

Rate Energy Charge Changes Monthly ($/kWh) Administration Charge $ 0.1870 per day System Access Service Charge As per Distribution Tariff Distribution Access Service Charge As per Distribution Tariff Local Access Fee (LAF) The LAF is a surcharge imposed by the City of Calgary and is not approved by the Alberta Energy and Utilities Board. The LAF is applicable to all services located within the City of Calgary.




EUB Order U2007-368



Large Commercial This rate schedule is for the provision of electricity services in accordance with the Regulated Rate Option Regulation (AR 262/2005) and the Electric Utilities Act, S.A. 2003, c. E-5.1. Applicability 1. Commercial Customers are eligible for this rate if a reasonable forecast of the customer’s


2. This rate applies to all commercial customers which obtain D310 or D410 service pursuant to the ENMAX Power Corporation Distribution Tariff.

Rate Energy Charge Changes Monthly ($/kWh) Administration Charge $0.1870 per day System Access Service Charge As per Distribution Tariff Distribution Access Service Charge As per Distribution Tariff Local Access Fee (LAF) The LAF is a surcharge imposed by the City of Calgary and is not approved by the Alberta Energy and Utilities Board. The LAF is applicable to all services located within the City of Calgary.



ENMAX Energy Corporation Appendix 3 – Board Approved Interim 2008 Terms and Conditions and Fee Schedule 2007-2008 Non-Energy RRO Negotiated Settlement Agreement Page 1 of 16


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ENMAX Energy Corporation Terms and Conditions for Regulated Rate Option Tariff

Table of Contents

1.0 DEFINITIONS .................................................................................................................................................. 3

2.0 INTERPRETATIONS ...................................................................................................................................... 5 2.1. CONFLICTS...................................................................................................................................................... 5 2.2. HEADINGS....................................................................................................................................................... 5

3.0 GENERAL PROVISIONS................................................................................................................................ 5 3.1. TARIFF............................................................................................................................................................ 5 3.2. EFFECTIVENESS OF TERMS AND CONDITIONS.................................................................................................... 6 3.3. AMENDMENT OF THE REGULATED RATE OPTION TARIFF .................................................................................. 6 3.4. ACCEPTANCE OF TERMS AND CONDITIONS ....................................................................................................... 6 3.5. MODIFICATION OF THE REGULATED RATE OPTION TARIFF................................................................................ 6

4.0 REGULATED RATE SERVICES.................................................................................................................... 6 4.1. PROVISION OF REGULATED RATE SERVICES ..................................................................................................... 6 4.2. ELIGIBILITY FOR REGULATED RATE SERVICES ................................................................................................. 6 4.3. BILLING AND PAYMENT................................................................................................................................... 7

4.3.1. Payment of Bill ......................................................................................................................................... 7 4.3.2. Overpayments........................................................................................................................................... 8 4.3.3. Returned Payment Fee .............................................................................................................................. 8 4.3.4. Dishonoured Payment............................................................................................................................... 9 4.3.5. Collection of Taxes ................................................................................................................................... 9 4.3.6. Sustainability of Customer Equipment ....................................................................................................... 9

4.4. INTERPRETATION OF REGULATED RATE SERVICE ............................................................................................. 9 4.4.1. Interruptions............................................................................................................................................. 9 4.4.2. Legislation................................................................................................................................................ 9 4.4.3. Tampering with Facilities ........................................................................................................................10 4.4.4. Use of Regulated Rate Service..................................................................................................................10

4.5. DISCONNECTION OF SERVICE ..........................................................................................................................10 4.5.1. Disconnection for Safety and System Security Reasons .............................................................................10 4.5.2. Disconnection Other Than for Safety Reasons ..........................................................................................10 4.5.3. Restoration of Service ..............................................................................................................................11 4.5.4. Fee Schedule............................................................................................................................................11 4.5.5. Credit ......................................................................................................................................................11 4.5.6. Security Deposit.......................................................................................................................................12 4.5.7. Proof of Incorporation or Status...............................................................................................................12

5.0 LIABILITY AND INDEMNIFICATION........................................................................................................12 5.1. DEFINITIONS ..................................................................................................................................................12 5.2. LIMITATION OF LIABILITY ..............................................................................................................................13 5.3. INDEMNITY ....................................................................................................................................................13 5.4. FORCE MAJEURE ............................................................................................................................................14

6.0 CONSEQUENTIAL LOSS ..............................................................................................................................14

7.0 MISCELLANEOUS.........................................................................................................................................14 7.1. COMPLIANCE WITH APPLICABLE LEGAL AUTHORITIES.....................................................................................14 7.2. NO WAIVER ...................................................................................................................................................14 7.3. LAW ..............................................................................................................................................................15 7.4. LEGISLATIVE AMENDMENTS ...........................................................................................................................15



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7.5. NOTICES ........................................................................................................................................................15



EUB Order U2007-368

TERMS AND CONDITIONS

FOR REGULATED RATE OPTION TARIFF

These Terms and Conditions set forth the terms and conditions upon which ENMAX Energy Corporation will provide Regulated Rate Service to Eligible Customers. The Regulated Rate Option Tariff Rate Schedules and Fee Schedule are applicable under these Terms and Conditions. 1.0 DEFINITIONS

The following words and phrases, whenever used in these Terms and Conditions or a Rate Schedule or a Fee Schedule, shall have the respective meanings set out below. (a) “Alberta Interconnected Electric System” means “interconnected electric system” as defined

in the EUA.

(b) “Board” means the Alberta Energy and Utilities Board.

(c) “Business Day” means a day other than a Saturday, Sunday or Statutory holiday in the Province of Alberta.

(d) “Current Bill Date” means the Current Bill Date as indicated on a Customer’s bill.

(e) “Customer” means a Person who is an Eligible Customer receiving or applying for Regulated Rate Service.

(f) “Disconnection” means the de-energization of any Site in the name of the Customer or the installation of a current limiting device at any such Site by the Owner of the Distribution System.

(g) “Distribution Tariff” means the applicable distribution tariff in effect with respect to the Distribution System.

(h) “Distribution System” means “electric distribution system” as defined in the EUA.

(i) “EEC” means ENMAX Energy Corporation.

(j) “Electricity” means “electricity” as defined in the EUA.

(k) “Electricity Services” means “electricity services” as defined in the EUA.

(l) “Eligible Customer” means an “eligible customer” as defined in the Regulation with respect to Sites located in the service territory of the Owner of the Distribution System.

(m) “EUA” means the Electric Utilities Act, S.A.2003, c.E-5.1, including the regulations enacted thereunder, as re-enacted, amended, supplemented or replaced from time to time.



EUB Order U2007-368

(n) “Facilities” means physical facilities including, without limitation, transmission and distribution lines, wires, transformers, meters, meter reading devices and other electrical apparatus.

(o) “Fee Schedule” means the fee schedule forming part of the Regulated Rate Option Tariff that sets out the additional charges that may be incurred by Customers for the provision of Regulated Rate Service pursuant to the Regulated Rate Option Tariff, as amended from time to time.

(p) “Force Majeure” means acts of God, strikes, walkouts, lockouts or other industrial disturbances, acts of the public enemy, wars, blockades, insurrections, riots, epidemics, landslides, lightning, earthquakes, fires, storms, floods, high water, washouts, inclement weather, laws, orders, restraints or acts of courts or other public, civil or military authorities, civil disturbances, explosions, breakdown or accident or necessity of repairs to equipment or lines of the electric transmission and distribution systems, loss, diminution or impairment of electrical service from generating plants, suppliers or the systems of others with which the Distribution System is interconnected, failure of any supplier or retailer to perform, failure, curtailment, interruption or reduction of the transmission or distribution systems’ capacity and any other event or circumstance, whether of the kind herein enumerated or otherwise, not reasonably within the control of EEC; provided that in no event shall the lack of finances or inability to perform due to financial condition or similar financial predicament constitute Force Majeure.

(q) “Interest Rate” means a rate equivalent to the one-year non-redeemable Royal Bank GIC rate for investments of $500 to $99,999.99 in effect five business days prior to the start of a quarter, which rate will be updated quarterly.

(r) “ISO” means the Independent System Operator as established pursuant to the EUA.

(s) “ISO Rules” means the rules established by the ISO from time to time pursuant to section 20(1) of the EUA.

(t) “Legislation” means statutes, regulations, regulatory requirements, governmental requirements, ISO Rules, orders, directives, rule or procedures or other similar instruments implemented, promulgated, issued, ordered or adopted by any government, government agency, regulatory body, the ISO or any other body having jurisdiction over EEC, Customers, Electricity Services or Regulated Rate Service.

(u) “Owner of the Distribution System” means the local distributor of electricity within a service territory, i.e. ENMAX Power Corporation for the Calgary service territory.

(v) “Person” includes an individual, firm, partnership, association, joint venture, body corporate, corporation, trustee, executor, administrator, legal representative, or organization.

(w) “Rate Schedule” means the rate schedule forming part of the Regulated Rate Option Tariff that sets out the charges to Customers for the provision of Regulated Rate Service pursuant to the Regulated Rate Option Tariff, as amended from time to time.



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(x) “Regulated Rate Option Tariff” means the tariff approved by the Board comprised of these Terms and Conditions and the Rate and Fee Schedules under which Regulated Rate Service is provided to Customers in accordance with the Regulation.

(y) “Regulated Rate Service” means the service that is required by the EUA and the Regulation to be provided in accordance with a regulated rate option tariff and such matters necessarily incidental thereto, including Electricity Services.

(z) “Regulation” means the Regulated Rate Option Regulation, AR 262/2005 as amended from time to time.

(aa) “Site” means the point of end use consumption.

(bb) “Terms and Conditions” means these Terms and Conditions for the Regulated Rate Option Tariff, as amended from time to time.

2.0 INTERPRETATIONS

2.1. Conflicts

If there is any conflict between a provision expressly set out in a Rate Schedule, a Fee Schedule and these Terms and Conditions, the express provision of the Rate Schedule or Fee Schedule, as the case may be, shall govern.

2.2. Headings

The division of these Terms and Conditions into sections, subsections and other subdivisions and the insertion of headings are for convenience of reference only and shall not affect the construction or interpretation of these Terms and Conditions.

3.0 GENERAL PROVISIONS

3.1. Tariff

EEC furnishes Regulated Rate Service under the Regulated Rate Option Tariff, which includes these Terms and Conditions, and the Rate and Fee Schedules. Customers will be billed for:

Electricity consumed by the Customer at a Site at a rate as set out in the applicable Rate Schedule of the Regulated Rate Option Tariff;

other charges, security deposits, and fees set out in the Regulated Rate Option Tariff, including the Fee Schedule;

charges and fees as levied by the Owner of the Distribution System pursuant to the Distribution Tariff;



EUB Order U2007-368

other charges, local access fees, surcharges or taxes imposed by the City of Calgary or the Owner of the Distribution System; and

any other charges, fees, other amounts or riders as may be approved by the Board from time to time as part of the Regulated Rate Option Tariff.

3.2. Effectiveness of Terms and Conditions

These Terms and Conditions form part of the Regulated Rate Option Tariff and have been approved by the Board. These Terms and Conditions will be in force until another Regulated Rate Option Tariff is approved.

3.3. Amendment of the Regulated Rate Option Tariff

Amendments to the Regulated Rate Option Tariff are to be made with the approval of Board, and will take effect as ordered by the Board.

3.4. Acceptance of Terms and Conditions

The application for, or the taking of, Regulated Rate Service by the Customer at any Site constitutes acceptance by the Customer of these Terms and Conditions and the assumption of all obligations set forth herein with respect to the Regulated Rate Option Tariff.

3.5. Modification of the Regulated Rate Option Tariff

No agent or employee of EEC is authorized to modify any provision, charge, or rate contained in the Regulated Rate Option Tariff or to bind EEC to perform in any manner inconsistent with the Regulated Rate Option Tariff.

4.0 REGULATED RATE SERVICES

4.1. Provision of Regulated Rate Services

EEC will provide Regulated Rate Service to Eligible Customers under the Regulated Rate Option Tariff in accordance with the applicable Rate Schedule, Fee Schedule and these Terms and Conditions.

4.2. Eligibility for Regulated Rate Services

In order to receive Regulated Rate Service at any time, a Customer must receive service from the Owner of the Distribution System pursuant to the Distribution Tariff and the Customer must comply with all of its obligations under the Distribution Tariff and applicable Legislation.

The owner of the property or premises requiring Regulated Rate Service with respect to a Site may open an account and be the Customer, unless there is a tenant or other person who has provided acceptable notice, in writing or by telephone, to EEC that it will be financially responsible for the Regulated Rate Service with respect to that Site, and if EEC’s credit



EUB Order U2007-368

requirements are met, such tenant or other person shall be the Customer. In the event such tenant or other person provides notice to EEC that it is vacating the Site, or such tenant or other person vacates the Site, the owner of the property or premises will again become financially responsible for Regulated Rate Service with respect to that Site and shall be the Customer.

If a Customer is not of legal age, a deposit may be required in order to obtain Regulated Rate Services.

A Customer may be required to supply information relating to load, creditworthiness and the manner in which the Regulated Rate Service will be utilized, and pay deposits, fees and charges as stated in EEC’s Rate Schedules, Fee Schedule and Terms and Conditions. EEC reserves the right to verify the age, status and identity of the Customer and the accuracy of the information provided with respect to Regulated Rate Service before Regulated Rate Service is provided.

4.3. Billing and Payment

4.3.1. Payment of Bill

The Customer receiving Regulated Rate Service at a Site will be billed for such Regulated Rate Service. When a change of occupancy occurs at a Site advance notice, in writing or by telephone, of such change must be given to EEC. EEC may accept a change of occupancy notification from a third party willing to accept responsibility for payment for Regulated Rate Service at a Site. The outgoing Customer may, at the discretion of EEC, be held responsible for all Regulated Rate Service supplied to the Site until the later of the vacancy or the date the change of occupancy notice is received and accepted by EEC.

The Customer shall pay all amounts required to be paid under these Terms and Conditions, including the amounts set out in section 3.1 of these Terms and Conditions, upon receipt of a bill for such amounts. Unless specifically provided otherwise in a Rate Schedule, or a Fee Schedule, EEC’s rates are based upon the furnishing of continuing Regulated Rate Service to the Customer’s premises at a single Site. EEC will issue a separate bill for each Site. However, the Customer and EEC may agree that EEC will issue one bill totaling charges for Regulated Rate Service delivered at more than one Site. Customers shall be billed for Regulated Rate Service according to the rate set out in the applicable Rate Schedule. Bills will be based upon actual Electricity consumption or upon estimated consumption as determined by EEC or the Owner of the Distribution System.

Bills shall be deemed rendered and other notices duly given when delivered to the Customer personally, when mailed to or left at the premises where Regulated Rate Service is provided or the last known address of the Customer or when delivered to the address specified in section 7.5 of these Terms and Conditions. Failure to receive such a bill from EEC will not entitle the Customer to any delay in the settlement of each account nor to any extension of the date after which a late



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payment charge, or any other remedy, becomes applicable. In the case of a dispute between EEC and the Customer, the Customer may dispute charges shown on the Customer’s bill or any other matters by contacting EEC, either in writing or by telephone, and advising EEC of the reason for the dispute. EEC will promptly investigate all disputes and advise the Customer of the results.

Payment shall be made by way of cash, cheque, automatic debit or other electronic instrument in the manner specified by EEC. Payment of a bill is accepted conditionally until such funds are fully and finally paid to EEC.

Any bill rendered to a Customer is due on the Current Bill Date as indicated on the bill. Late payment charges, at a rate established by EEC from time to time and specified in the bill will be applicable to the total current charges outstanding, no less than twenty-five (25) days following the Current Bill date. Customers who fail to make payments in full on time will also be subject to normal credit action, which may include, but is not limited to one or more of the following:

reminder letters, telephone calls, emails or other correspondence or notification;

use of collection agencies;

requiring prepayment and payment of all outstanding amounts before additional Regulated Rate Service is provided at any Site in the name of the Customer;

assessment of a deposit or additional deposit;

transferring balances owing from one account in the name of the Customer to another account also in the name of the Customer;

initiating Disconnection at any Site under any account in the name of the Customer; and

legal action.

4.3.2. Overpayments

If the Customer pays EEC an amount in excess of what is owed to EEC, the excess amount will be carried as a credit balance on the Customer’s account and applied to bills for future Regulated Rate Service. If a Customer is no longer receiving Regulated Rate Service, EEC will refund credit balances.

4.3.3. Returned Payment Fee

EEC may assess a returned payment fee, as outlined in the Fee Schedule attached to these Terms and Conditions, to any Customer whose instrument for payment to



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EEC is dishonoured, rejected or reversed by any financial institution when presented for payment by EEC.

4.3.4. Dishonoured Payment

Receipt by EEC of a cheque or other payment instrument that is subsequently dishonoured shall not be considered valid payment. EEC reserves the right to reject post-dated cheques.

4.3.5. Collection of Taxes

EEC shall collect all sales, excise, or other taxes imposed by governmental authorities with respect to Regulated Rate Service.

4.3.6. Sustainability of Customer Equipment

The Customer assumes full responsibility for the proper use of Electricity or Regulated Rate Service provided by EEC and for the condition, installation, suitability and safety of any and all Facilities or any other equipment, wires, cables, devices or appurtenances on the Customer’s premises or located on premises owned, controlled or occupied by the Customer.

4.4. Interpretation of Regulated Rate Service

4.4.1. Interruptions

EEC cannot guarantee an uninterrupted supply of Electricity. EEC may discontinue or otherwise curtail, interrupt or reduce the supply of Electricity or Regulated Rate Service without liability whenever EEC reasonably determines, or when EEC is directed by the ISO, the Owner of the Distribution System, or any governmental, regulatory or civil authority that such a discontinuation, curtailment, interruption or reduction is necessary to facilitate safety, law enforcement or the construction, installation, operation, maintenance, reliability, repair, replacement or inspection of any Facilities, the Distribution System or the Alberta Interconnected Electric System; or due to any other reason, including emergencies, forced outages, potential damage to any Facilities, the Distribution System or any part of the Alberta Interconnected Electric System or Force Majeure.

4.4.2. Legislation

The Customer acknowledges and agrees that both it and EEC are bound by the Legislation.



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4.4.3. Tampering with Facilities

If EEC determines that there has been an unauthorized use of Electricity or Regulated Rate Service including but not limited to any tampering with a meter or other Facilities, unauthorized connection or reconnection, or theft, fraud, intentional or unintentional use of Electricity whereby EEC is denied full compensation for services provided, EEC may initiate Disconnection and charge the Customer for any unauthorized use of Electricity, all damages suffered by EEC, and all costs incurred in recovering any such amounts. Nothing in this section shall be deemed to constitute a waiver of any other rights of redress, which may be available to EEC, or to limit in any way any legal recourse which may be open to EEC.

4.4.4. Use of Regulated Rate Service

The Customer shall not use its Electricity or Regulated Rate Service in a manner so as to cause undue interference with any other Customer’s use of Regulated Rate Service or any user of the Alberta Interconnected Electric System such as an abnormal disturbance to the voltage, frequency and waveform of the Electricity supply.

4.5. Disconnection of Service

4.5.1. Disconnection for Safety and System Security Reasons

EEC reserves the right, without liability, to initiate Disconnection at any time without notice, or to refuse to make such Regulated Rate Service available to the Customer, where, in EEC’s reasonable opinion the use of Regulated Rate Service or provision of Electricity may cause damage to Facilities, the Distribution System or the Alberta Interconnected Electric System or interfere with or otherwise disturb any other service provided by EEC.

EEC will resume Regulated Rate Service when the condition has been rectified to EEC’s satisfaction acting reasonably.

4.5.2. Disconnection Other Than for Safety Reasons

EEC may at any time, after having given at least 48 hours’ prior oral or written notice to a Customer and without any further notice, initiate Disconnection if the Customer:

violates any provision of these Terms and Conditions (including the provision of a deposit when requested or failure to pay for the Regulated Rate Service);



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has instituted by or against it any formal or informal proceeding for the dissolution or liquidation of, settlement of claims against, or winding up of the affairs of the Customer; or

ceases or threatens to cease to carry on business, makes or agrees to make a bulk sale of assets without complying with applicable law or commits an act of bankruptcy, or otherwise acknowledges its insolvency;

tampers with any meters or any Facilities that may affect metering of Electricity consumption at a Site;

provides EEC with incorrect information or makes fraudulent or unauthorized use of Regulated Rate Service; or

EEC has not been provided with sufficient information to bill a Customer or the premises or property served by a Site reasonably appears to EEC to be vacant or not occupied by a known Customer.

4.5.3. Restoration of Service

Following a Disconnection, the Customer shall pay the following amounts prior to receiving further Regulated Rate Service:

any unpaid amounts owing to EEC;

an application fee; and

a security deposit in such amount, if any, as determined by EEC in its sole discretion as contemplated in section 4.5.6 of these Terms and Conditions.

4.5.4. Fee Schedule

EEC reserves the right to impose reasonable fees and charges pursuant to the various provisions of these Terms and Conditions as approved by the Board. The fees and charges shall be set out in the Fee Schedule which forms part of these Terms and Conditions, and may be amended from time to time in accordance with section 3.3 of these Terms and Conditions.

4.5.5. Credit

Upon the request of EEC, the Customer agrees to provide information, including the disclosure of its financial statements, banking information, payment history and credit standing and any other information reasonably required by EEC, to evaluate the Customer’s creditworthiness. The Customer represents to EEC that all oral or written financial information furnished by or on behalf of the Customer to EEC is accurate and complete in every respect on the date that the information



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is provided. A security deposit may be assessed pursuant to section 4.5.6 of these Terms and Conditions.

4.5.6. Security Deposit

A guarantee deposit as security for payment in an amount, determined by EEC, may be required prior to or during the provision of Regulated Rate Service pursuant to this Regulated Rate Option Tariff. The maximum deposit will be no greater than twenty-five per cent (25%) of a Customer’s average annual bill. In cases where there is less than twelve (12) months of billing history, EEC may estimate the Customer’s average annual bill. Guarantee deposits, unless otherwise applied, will be refunded with interest at the Interest Rate to the Customer after the Customer establishes a satisfactory payment record.

When Regulated Rate Service is discontinued, a guarantee deposit will be applied by EEC against any outstanding balance of the Customer to EEC. EEC shall refund, with interest at the Interest Rate, to the Customer any portion of such deposit not applied to an outstanding balance.

4.5.7. Proof of Incorporation or Status

Commercial customers may be required to provide proof of incorporation to set up an account in the name of a corporate entity. Similar documentation may be required from entities, other than natural persons, seeking to set up an account.

5.0 LIABILITY AND INDEMNIFICATION

5.1. Definitions

5.1.1 In this Article: 5.1.1.1“direct loss or damage” means direct physical damage, injury or loss, but

does not include loss of profits, loss of revenue, loss of production, loss of earnings, loss of contract or any other indirect, special or consequential loss or damage whatsoever;

5.1.1.2 “EEC” includes:

5.1.1.2.1 EEC, its affiliates, contractors, agents, authorized representatives and assigns, and the directors, officers and employees (while those employees are acting within the course and scope of their employment) of each of them; and

5.1.1.2.2 for the purposes of clause 5.1.1.2.1, “affiliate” has the meaning given to it in the Business Corporations Act (Alberta).



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5.2. Limitation of Liability

5.2.1 EEC does not guarantee or promise uninterrupted service. Except for direct loss or damage caused by the negligence of EEC, EEC shall not be liable to any Customer or other person in law, equity, tort or contract for any loss, damage, injury or claim of any nature whatsoever, arising out of or in any way connected with its performance under these Terms and Conditions, the provision of Regulated Rate Service or any other services provided under these Terms and Conditions, or any failure, estimated data errors, defect, fluctuation, reduction, de-energization, suspension, curtailment or interruption in the provision of Regulated Rate Service or any other services provided under these Terms and Conditions.

5.3. Indemnity

5.3.1 The Customer shall indemnify and hold harmless, and at the option of EEC, defend EEC from and against all claims, actions, costs, fees (including legal fees and disbursements on an indemnity basis), judgments, fines, penalties and any liability in law, equity, tort or contract for any loss, damage, injury or claim of any nature whatsoever, brought against EEC which arise from, result from, or are in any way connected with any act, omission or failure of the Customer arising from, resulting from or in any way connected with these Terms and Conditions or EEC’s Regulated Rate Option Tariff, or under any other arrangement or agreement between the Customer and EEC, or between the Customer and any third party.

Without limiting the generality of the preceding paragraph, the Customer shall also indemnify and hold harmless, and at the option of EEC, defend EEC from and against all claims, actions, costs, fees (including legal fees and disbursements on an indemnity basis), judgments, fines, penalties and any liability in law, equity, tort or contract for any loss, damage, injury or claim of any nature whatsoever, brought against EEC by any person, which arise from, result from, or are in any way connected with:

the routine presence in or use of Electricity over the Facilities or any wires, cables, devices or other facilities owned or controlled by the Customer;

the failure of the Customer to perform any of the Customer’s duties and obligations as set out in these Terms and Conditions;

the Customer’s improper use of Electricity or of electric wires, cables, devices or any Facilities; or

the initiation of a Disconnection in accordance with these Terms and Conditions.



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5.4. Force Majeure

5.4.1 If an event or circumstance of Force Majeure occurs that affects EEC’s ability to provide Regulated Rate Service or any other services provided under these Terms and Conditions, so far as they are affected by the Force Majeure or its consequences, the Regulated Rate Service shall be suspended until the Force Majeure or its consequences are remedied, and for such period thereafter as may reasonably be required to restore the Regulated Rate Service.

5.4.2 EEC is not liable to Customers or any other person in law, equity, contract or tort for

any loss, damage, injury or claim of any nature whatsoever arising from or connected in any way with the amount or lack of notice given by EEC of an event of Force Majeure.

6.0 CONSEQUENTIAL LOSS

NEITHER EEC OR THE CUSTOMER SHALL BE LIABLE TO THE OTHER FOR ANY SPECIAL, INDIRECT OR CONSEQUENTIAL DAMAGES RESULTING OR ARISING OUT OF PERFORMANCE UNDER THESE TERMS AND CONDITIONS, INCLUDING, WITHOUT LIMITING THE GENERALITY OF THE FOREGOING, LOSS OR DAMAGE RESULTING FROM LOSS OF USE, REVENUE, PROFIT OR OPPORTUNITY WHETHER OR NOT A PARTY HAS BEEN ADVISED OF THE POSSIBILITY OF SUCH LOSS OR DAMAGE.

7.0 MISCELLANEOUS

7.1. Compliance with Applicable Legal Authorities

EEC and the Customer are subject to, and shall comply with, all existing or future applicable Legislation. EEC will not violate, directly or indirectly, or become a party to a violation of any requirement of any applicable Legislation in order to provide Regulated Rate Service. EEC’s obligation to provide Regulated Rate Service is subject to the condition that all requisite governmental and regulatory approvals for the provision of Regulated Rate Service have been obtained and will be maintained in force during such period of service.

7.2. No Waiver

The failure of either Party to insist in any one or more instances upon strict performance of any provisions of these Terms and Conditions, or to take advantage of any of its rights hereunder, shall not be construed as a waiver of any such provisions or the relinquishment of any such right or any other right hereunder, which shall remain in full force and effect. No term or condition of these Terms and Conditions shall be deemed to have been waived and no breach excused unless such waiver or consent to excuse is in writing and signed by the Party claimed to have waived or consented to excuse.



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7.3. Law

These Terms and Conditions shall be governed by the laws of the Province of Alberta and the federal laws of Canada applicable in the Province of Alberta, without regard to principles of conflicts of law. Any lawsuit arising in connection with these Terms and Conditions shall be brought in the courts of the Province of Alberta.

7.4. Legislative Amendments

EEC reserves the right to terminate any service under the Regulated Rate Option Tariff upon the happening of any change or amendment to applicable Legislation (or the application or implementation of same).

7.5. Notices

Unless otherwise stated herein, all notices, demands or requests required or permitted under these Terms and Conditions shall be in writing and shall be personally delivered, mailed or sent by facsimile transmission (with the original transmitted by any of the other aforementioned delivery methods) addressed as follows:

If to the Customer: to the address and the addressee on record with EEC.

If to EEC regarding billing, credit, or customer information:

ENMAX Energy Corporation 141 – 50th Avenue SE Calgary, Alberta T2G 4S7 Phone Number: (403) 310-2010

Fax Number: (403) 219-2146

A Party may change the address or addressee from time to time by giving written notice of such change to the other Party in accordance with this section. Any notice, demand or request made, given or delivered hereunder is considered delivered; when sent by facsimile, on the next Business Day following a confirmed facsimile; when mailed, at the end of the fourth (4th) Business Day after mailing; when hand delivered, at the time of delivery where proof of delivery date is provided.



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REGULATED RATE OPTION TARIFF

FEE SCHEDULE The fees and charges contained in this schedule are non-refundable and are charged in all circumstances. These fees apply to Customer required services as described in the Regulated Rate Option Terms and Conditions. Any applicable fees in respect of ENMAX Power Corporation’s Distribution Tariff will flow through to Regulated Rate Option Customers. Dishonoured Payments: $25.00 per dishonoured payment

This fee applies to all dishonoured payments for any reason. Security Deposit: Special – per customer merit

A security deposit may be requested from a Customer, or the Customer’s credit history may be accepted. Late Payment Charge: 3.25% of the total current charges

A one-time charge of 3.25% will be applied, no less than twenty five (25) days following the Current Bill Date indicated on the bill, to total current charges outstanding. Final Notice: $15 per notice

Applied to a customer account, when the account is over 60 days in arrears and a final letter of notice has been issued.

auc€¦ · 2007 to december 31, 2008 (settlement or nsa). this settlement was reflected in te rms...

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