Decision 2004-098: ENMAX - 2005-2006 Regulated Rate Tariff ...€¦ · 2005-2006 Regulated Rate Tariff Part C: Energy Price Setting Plan Negotiated Settlement October 26, 2004. ALBERTA

Alberta Energy and Utilities Board

Decision 2004-098

ENMAX Power Corporation 2005-2006 Regulated Rate Tariff Part C: Energy Price Setting Plan Negotiated Settlement October 26, 2004

ALBERTA ENERGY AND UTILITIES BOARD Decision 2004-098: ENMAX Power Corporation 2005-2006 Regulated Rate Tariff Part C: Energy Price Setting Plan Negotiated Settlement Application No. 1348671 Published by Alberta Energy and Utilities Board 640 � 5 Avenue SW Calgary, Alberta T2P 3G4 Telephone: (403) 297-8311 Fax: (403) 297-7040 Web site: www.eub.gov.ab.ca

http://www.eub.gov.ab.ca/

Contents

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

2 VIEWS OF THE PARTIES................................................................................................. 2 2.1 EPC ................................................................................................................................ 2 2.2 CPs Supporting the NS .................................................................................................. 5

3 NEGOTIATED SETTLEMENT GUIDELINES............................................................... 5

4 VIEWS OF THE BOARD.................................................................................................... 6 4.1 Fairness of the Negotiated Settlement Process .............................................................. 6 4.2 CCG/AbCom Concerns.................................................................................................. 7 4.3 Public Interest ................................................................................................................ 9

5 ORDER ................................................................................................................................ 10

ATTACHMENT 1 - NEGOTIATED SETTLEMENT APPLICATION .............................. 11

EUB Decision 2004-098 (October 26, 2004) � i

ALBERTA ENERGY AND UTILITIES BOARD Calgary Alberta ENMAX POWER CORPORATION 2005-2006 REGULATED RATE TARIFF PART C: ENERGY PRICE SETTING PLAN Decision 2004-098 NEGOTIATED SETTLEMENT Application No. 1348671 1 INTRODUCTION AND BACKGROUND

Pursuant to its Revised Negotiated Settlement Guidelines (Revised Guidelines),1 the Alberta Energy and Utilities Board (the Board) received an application (Attachment 1) dated June 7, 2004 from ENMAX Power Corporation (EPC) requesting approval to commence a Negotiated Settlement Process (NSP) for an Energy Price Setting Plan (EPSP) for EPC�s 2005-2006 Regulated Rate Tariff (RRT). The Negotiated Settlement (NS) for the EPSP for EPC�s 2004 RRT, approved in Decision 2004-042, and expires at the end of 2004. ENMAX Energy Corporation (EEC) is the RRT Provider in EPC�s service area.2 The Board issued Part A: Decision 2004-053 dated June 29, 2004 approving EPC�s request to negotiate an EPSP for EPC�s 2005-2006 RRT. In Decision 2004-053, the Board outlined a new requirement for participation in a NSP. Specifically, a party wishing to participate in a NSP as an intervener must first file a Request to Participate with the Board. The Request to Participate is required to include a detailed statement describing the nature of the party�s interest in the proceeding and the nature of the party�s intended participation. The Request to Participate must also detail the scope of the intended party�s participation. The Board notes that, pursuant to the public notice published by EPC, interveners were given until July 12, 2004 to submit their Requests to Participate in the NSP with the Board. The Board issued Part B: Decision 2004-061 dated July 20, 2004 approving the Consultation Parties (CP) to the EPC EPSP NSP. The Board ruled in Decision 2004-061 that the direct participation of the Utilities Consumer Advocate (UCA), Consumers Coalition of Alberta (CCA) and Public Institutional Consumers of Alberta (PICA) in the NSP and the participation of Hansen Development Consulting (HDC) and Care Center Group and Aboriginal Communities (CCG/AbCom) through the UCA (should they choose to participate in this manner) would enhance the effectiveness of the NSP. The direct participation of the Constellation Energy Group (Constellation) was denied.

1 Informational Letter IL 98-04 Revised Negotiated Settlement Guidelines: Tolls, Tariffs, and Terms and

Conditions of Service (February 4, 2003)

EUB Decision 2004-098 (October 26, 2004) � 1

2 City of Calgary

http://www.eub.gov.ab.ca/BBS/requirements/ils/ils/il98-04-revised-2003.htm

http://www.eub.gov.ab.ca/bbs/documents/decisions/2004/2004-042.pdf




2005-2006 Regulated Rate Tariff Part C: Energy Price Setting Plan Negotiated Settlement ENMAX Power Corporation

The Board ruled in Decision 2004-053 that, if a NS had not been achieved by September 30, 2004, EPC must file an application for approval of EPC�s 2005-2006 RRT EPSP on or before November 1, 2004. By way of letter received September 29, 2004, EPC indicated that EPC and the CP had reached an agreement on substantive issues of the RRT EPSP for 2005-2006, but that a NS was not complete at that time and EPC was not in a position to file an application to approve an NS. EPC expected that it would be able to file an application for the RRT EPSP NS either by October 8, 2004 or shortly thereafter. By way of Board letter dated September 30, 2004, the Board recognized that the time available to EPC and the CP to reach an RRT EPSP NS was affected to some degree by the newly introduced Board process requiring interested parties to apply for involvement in a NSP. The Board therefore considered it reasonable to grant an extension beyond the September 30, 2004 deadline contained in Decision 2004-053 for EPC to submit a formal NS document. On October 15, 2004, EPC submitted a 2005-2006 RRT EPSP NS to the Board and interested parties. In a letter dated October 18, 2004, the Board requested clarification of certain items contained in the NS by way of information requests. EPC submitted responses to these information requests on October 21, 2004. By way of Board letter dated October 18, 2004, the Board gave notice to interested parties that it would deal with the NS without further process unless valid objections were received by October 22, 2004. The Board received a letter from the Care Center Group/Aboriginal Communities (CCG/AbCom) on October 22, 2004 and a reply to the CCG/AbCom letter from the Utilities Consumer Advocate (UCA) on October 22, 2004. The Board provided the CCG/AbCom the opportunity to reply to the UCA, if they chose, no later than October 25, 2004. The Board received a reply from the CCG/AbCom on October 25, 2005. No other comments or objections were received from any interested party. For administrative purposes of this Decision, the Board considers the record to have closed on October 25, 2004. 2 VIEWS OF THE PARTIES

2.1 EPC EPC considered that the NSP was fair, in that adequate notice was given, and all parties who the Board determined were eligible to participate were given the opportunity to participate fully in the process. EPC noted that where a participant was unable to attend a meeting personally, arrangements for participation by telephone were made. EPC further noted that a member of Board staff, the Independent Advisor and the Third Party Advisor also participated in the NSP.

2 � EUB Decision 2004-098 (October 26, 2004)




EPC stated that negotiations and discussions between EEC and the CP began on July 22, 2004 and continued until October 14, 2004, and resulted in the NS. EPC submitted that the parties to the NS had agreed to a procurement process involving requests for proposals (RFP(s)) to be held under the supervision of the Independent Advisor (IA) in order to acquire energy for the RRT for all of 2005 and the first two quarters of 2006. EPC stated that the parties would first attempt to fill the RRT Load through the acquisition of Full Load Products and that, to that end, bidders would be invited to offer a percentage of the actual RRT Load for every hour of the relevant term, to be settled as a financial swap against the hourly Pool Price. EPC noted that if less than 100% of the RRT Load was acquired as Full Load Products, bidders may be invited to offer a fixed volume of either Base Load or On Peak energy to be settled as a financial swap against the hourly Pool Price. EPC stated that additional energy requirements would be acquired through an intersession procurement process or through Alternative Hedges. EPC submitted that the basis for the NS had been well-substantiated, to the extent possible without violating the confidentiality provisions of the Guidelines and the Confidentiality Agreement entered into among EEC and the CP. EPC stated that the CP were made up of customer groups representing a broad cross-section of both Rate Class Customers (RCC) and Non-Rate Class Customers (NRCC). EPC submitted that the rates that would result from the EPSP complied with the requirements of the Regulated Default Supply (RDS) Regulation, which required that a �transition rate� be offered to both RCC and NRCC, that the potential for periodic adjustments be minimized, and that the procurement risk of acquisition remain with EEC, as the regulated rate provider. EPC also submitted that the rates that result from the EPSP were just and reasonable. EPC noted that the EPSP effectively resulted in the RRT Load being hedged, using market-priced financial products acquired through a procurement protocol agreed to by a broad cross-section of EPC�s RRT customers, and that this would provide a significant degree of rate stability to RRT customers. EPC submitted that the NS and the EPSP described in the NS were in the public interest and ought to be approved as requested. EPC stated that the key principles of the EPSP include the following:

(a) RRT customers assume price and volume risk, prior to the start of each quarter.

(b) EEC assumes all price and volume risk within a quarter.

(c) Prior to the start of each quarter, EEC will: a. forecast load for the upcoming quarter and the remaining quarters in the Term by

hour, including losses and Unaccounted For Energy (UFE); b. forecast prices for the upcoming quarter and the remaining quarters in the Term by

hour, based upon the forward market; and c. forecast a Target Portfolio for each month of the upcoming quarter.

(d) Prior to the start of each quarter, the CP may, with the agreement of EEC, substitute

some or all of the Product proposed to be purchased by EEC with other products. Alternatively, rather than purchasing replacement products for the Products proposed by EEC, the CP may choose to have customers assume price risk in relation to that portion of the load that would have been covered by the proposed Products.



(e) The energy supply for RCC and NRCC customers will be administered as a single pool.

For 2005-2006, the Parties have agreed to use the North American Electric Reliability Council (NERC) �west� definition of On Peak Hours (6x16). Accordingly, in order to implement a single energy supply acquisition pool, the parties have agreed that an inter-class price adjustment may be required in order to ensure equity as between RRC and NRCC customers, and EEC has agreed to implement such a price adjustment provided that the implementation of the adjustment is practicable and has no adverse financial impact on EEC.

(f) EEC will assume all counterparty risks.

(g) For staffing and administering of the EPSP, the Parties have agreed that EEC will receive $0.50 for each MWh of actual metered load.

(h) The RFP process will be similar to the RFP process that was used to procure products

for the 2004 RRT. ENMAX Energy Marketing Inc. (EEMI) may be a potential bidder in the RFP rounds. Therefore, a conflict screen will be put in place between ENMAX employees that will participate in the bid and the ENMAX employees that will be procuring the energy through the RFP(s). As in the RFP process for the 2004 RRT, qualifying bids will be assigned a letter by the IA, ranked based on price and accepted in accordance with the Procurement Protocol.

(i) EEC will receive a $/MWh risk premium for that portion of the RRT Load that is not

covered by Full Load Products. The value of the risk premium will be included in the rate calculation, but will not be determined or disclosed until the Full Load Products have been procured.

(j) EEC has an option to, and may supply, a limited amount of volume at a price lower than

what would be otherwise procured from third party offers. This option can only be exercised after defined volume has been procured from third parties through RFPs.

(k) EEC will include in the RRT rates its estimated external costs and the estimated costs

associated with the IA, the Third Party Advisor, the CP incurred during the negotiation phase, and subsequently, for each quarter. These costs will be submitted to the Board for approval, and to the extent that the costs approved by the Board differ from the estimated costs, the rates will be adjusted to reconcile that difference, as set out in Appendix 3 of the EPSP.

(l) In the second quarter of 2005, an adjustment factor to reconcile initial load settlement

and final load settlement data will be included in the rates for energy acquired in January, February, March, April and May 2004, as directed in Decision 2003-086.

EPC stated that the NS reflected a number of compromises respecting the different interests of the various parties, and had been negotiated on the basis that the NS was contingent on the Board�s acceptance of the entire NS (with the exception of Section 16 of the Terms of Settlement), as permitted under article 12.3 of the Guidelines.


http://www.nerc.com/

http://www.nerc.com/



2.2 CPs Supporting the NS

The following CP members were signatories to the NS and supported its approval by the Board:

• UCA • CCA • PICA

As per Decision 2004-061, the CCG/AbCom and HDC had the opportunity to have their interests represented by the UCA in this process. For the purposes of this Decision however, the Board considers that the term �Consultation Parties� or �CP�, refers to the UCA, CCA, and PICA. 3 NEGOTIATED SETTLEMENT GUIDELINES

The Board notes that all three CPs, who represent a wide cross-section of potential RRT consumers, agreed that the NS should be approved. The Board has been presented with an application for approval of a negotiated settlement in its entirety. The Board notes that the section 135 EUA limits the Board�s discretion when it considers a negotiated settlement.

If the parties negotiate a settlement on the basis that the settlement is contingent on the Board�s accepting the entire settlement, the Board must either approve the entire settlement or refuse it.

In the circumstances, the Board considers that there are two matters that the Board must review:

1. Whether EPC�s NSP was fair and in accordance with the Board�s Guidelines; 2. Whether the NS is reasonable and fair to all parties and in the public interest.

The criteria for NSPs are set out in section 1.3 of the Guidelines:

• Parties involved in the process will participate in good faith. • The NSP must be:

• open and fair to all interested parties; • conducted on a confidential, without prejudice basis, and • sufficiently flexible to accommodate unique circumstances and requirements.

Sufficient information must be available at the outset and during the course of the NSP to facilitate understanding and review of the issues being negotiated. The Guidelines make it clear that participation in the process is voluntary and the information provided during the process should be available to all parties having an interest in the issues subject to negotiation. Section 3.1 requires proper notice of the process to be given and documented in any resulting NS. Sections 7 and 8 of the Guidelines provide for the involvement of Board staff in the NSP.



Sections 10 and 12 of the Guidelines contemplate an application for approval of a NS being filed with the Board. Section 10 emphasizes that the onus is on the applicant to provide sufficient evidence to support the application, whereas Section 12 sets out procedures and criteria the Board may follow in considering an application for approval of a NS. 4 VIEWS OF THE BOARD

4.1 Fairness of the Negotiated Settlement Process As noted above, the first question for the Board is whether the EEC NSP was fair and in accordance with the Guidelines. In a letter3 dated June 24, 2004, the Board notes that notice was provided to all parties that the Guidelines are to be amended requiring that any party wishing to participate in a NSP as an intervener must first file a �Request to Participate� with the Board. The �Request to Participate� shall include a detailed statement describing the nature of the party�s interest in the proceeding and the nature of the party�s intended participation. The �Request to Participate� should also detail the scope of the intended party�s participation. In evaluating whether or not a particular NSP was conducted in a fair manner and in accordance with the Guidelines, the Board will consider if proper notice has been provided, whether parties wishing to participate were given the opportunity to file a �Request to Participate�, and if any objection to the process was received, if due process has been provided to the participants by allowing for meaningful participation in the process , if Board staff has participated as an observer in the settlement discussions, and if all parties expressing an interest have approved of or not objected to the terms of the NS. The Board considers that proper notice of the settlement process was provided as set out in Appendix B to the Application. With respect to the present Application, the Board is satisfied that all parties were provided the opportunity to present submissions respecting requests to participate. The Board dealt with these submissions as follows in Decision 2004-061:

The Board considers that the UCA, CCA and PICA costs can be minimized through a coordinated approach respecting their intervention efforts. Further, a coordinated approach will also promote the probability of a timely negotiated settlement. On this basis the Board will allow the CCA and PICA to participate in the NSP. The Board considers that it would be cost effective for smaller groups like the HDC and the CCG/AbCom to express their concerns to the UCA and have the UCA represent the interests of these smaller consumer groups under a common umbrella. Indeed, even without an initiative by these groups, the Board expects that, in accordance with its mandate, the UCA would ensure that it is fully appraised of the concerns and interests of all members of its constituent group in order to provide effective and complete representation in the NSP. The Board notes from the late Request of the CCG/AbCom that this process already is taking place to some extent�.

3 Attached to Decision 2004-053 6 � EUB Decision 2004-098 (October 26, 2004)



For all of the above reasons, the Board considers that the direct participation of UCA, CCA and PICA in the NSP and the participation of HDC and CCG/AbCom through the UCA will enhance the effectiveness of the NSP.

The Board notes that the UCA, CCA and PICA formed the CPs for the NS. EEC and the CPs met on several occasions to reach the NS. A Board observer attended all appropriate meetings. EEC and the CPs retained an IA and Third Party Advisors, who participated in the meetings. The Board notes that the UCA extended an invitation4 to the Utilities Consumer Advocate Society of Calgary to attend negotiating sessions as observers subject to the signing of the required confidentiality agreements. The Board observer did not advise the Board of any concerns related to the fairness of the NSP. The Board considers that the evidence confirms that the NSP was fair and that there was meaningful participation in the process by the parties. 4.2 CCG/AbCom Concerns In response to the Board�s letter of October 18, 2004, the CCG/AbCom submitted the following:

In consequence of earlier discussions with the UCA and the Board�s decision, we provided our input or suggestions concerning the negotiation process. We attach a letter (dated July 22, 2004) and covering e-mail message that we sent to the UCA documenting our concerns. We have never resisted cooperation with the UCA. We expected to provide further input to the NSP through the UCA, and asked for the UCA�s advice and direction in this regard. Since the Decision, we have received no communication from the UCA or the other appointed consultation parties concerning the process or substance of the negotiations or the proposed settlement. It is unclear how the UCA would be able to provide �effective and complete representation� without two-way communication. In the absence of evidence of consultation with other intervener groups, we ask that the proposed plan be submitted for approval in the usual process of any other application. In addition, we request that the Board reconsider and clarify the status of CCG and AbCom as interveners in this matter. (Bolded date added for clarification) 5

The UCA replied as follows:

Mr. Ackroyd and Mr. Bellows have been in contact with this office many times since July 22, 2004, the date of Mr. Ackroyd�s letter to the UCA regarding the Enmax negotiations� The UCA has demonstrated its willingness to work with the CCG/AbCom and like groups by facilitating observer status at negotiations, subject to the signing of the required confidentiality agreements. While this option is presented as one of many in Mr. Ackroyd�s letter of July 22, 2004, no further request was made regarding that option. 6

4 UCA letters to Mr. Hansen dated August 6, 2004 and August 13, 2004 5 CCG/AbCom letter dated October 22, 2004. 6 UCA letter dated October 22, 2004.



The CCG/AbCom responded as follows:

We have no reason to believe that the proposed settlement is unacceptable. We simply do not know enough about it or how it came about. What was given and what was taken away? What was gained and what was lost? The UCA seems to say in its letter of October 22, 2004 that: short of a formal reporting relationship (whatever that may mean) supported by a confidentiality agreement there is no duty to report to anyone else, whether residential, native or farmer. The whole process is shrouded in secrecy. 7

According to Section 6 of the Board�s Guidelines, negotiated settlement meetings are not open to the public and any participant may be required to sign a confidentiality agreement. The Board considers that it would be detrimental to RRT customers to have a NSP that publicly disclosed details of procuring energy from a competitive market. Accordingly, the Board agrees with the UCA that if the CCG/AbCom or other parties expected to be fully informed during the course of negotiations, the Board considers to be reasonable the UCA�s view that the CCG/AbCom execute an appropriate confidentiality agreement as required of the CP. On the one hand, it is clear from Decision 2004-061 that the CCG/AbCom was expected to bring their interests forward through the UCA rather than participating directly in the NS. On the other hand, it was equally clear that the UCA was expected to take an active role in ensuring that those parties the Board directed to participate through the UCA would be adequately represented. The Board finds, on balance, that the CCG/AbCom did have an adequate opportunity to participate through the UCA. If it became clear that negotiations were proceeding and the CCG/AbCom required information as to the negotiations, it appears to the Board that the CCG/AbCom did have sufficient contact with the UCA that those inquiries could reasonably have been made. In these circumstances, having dealt with the �Request to Participate� by the CCG/AbCom in Decision 2004-061, the Board considers it would now be unfair to the CP and EPC to provide the CCG/AbCom with a second opportunity to provide comments on the NS. Accordingly, the Board is satisfied that the NS was reached fairly and in accordance with the Board�s Guidelines. There is clearly an onus on both parties to ensure effective communication in circumstances such as these, and it appears to the Board that there has been a failure of communication, to some extent, between the UCA and the CCG/AbCom. However, it is not clear to the Board where the failure of communication occurred in the circumstances. While the Board is persuaded that the CCG/AbCom did have an adequate opportunity to participate through the UCA, the Board urges the UCA to develop business practices to ensure that the UCA�s expectations of parties, including any requirements for representation through the UCA, are clearly communicated at the outset. The Board does expect the UCA to take an active role in ensuring the effective representation of those parties who are not approved for direct participation in a NSP.

7 CCG/AbCom letter dated October 25, 2004. 8 � EUB Decision 2004-098 (October 26, 2004)


4.3 Public Interest

The second question for the Board is whether the NS contains elements that could produce rates that are not just and reasonable. The Board considers that the expressions of support by the CPs are of considerable comfort in assessing the justness and reasonableness of the EPSP. The Board considers these parties, who are well known to the Board, to be experienced and knowledgeable. In general, the Board considers that the NS has a well-substantiated, rational basis and was complete and adequate to support the Application, as required by the Board�s Guidelines. Accordingly, the Board is satisfied with the framework of the EPSP as set out in the NS. The RDS Regulation indicates that when considering an application for approval of a RRT, the Board must have regard for the principle that a RRT must provide the owner with a reasonable opportunity to recover the prudent costs and expenses incurred by the owner and a reasonable return. The Board considers that the risk compensation value is a key consideration in the Board�s determination of whether the NS is in the public interest. The Board notes from BR-EPC-1 that parties to the NS have agreed to keep the risk compensation value confidential to avoid any possible influence on the market RFP offers for Full Load Products. The Board also notes from the Application that the risk compensation value �will be included in the rate calculation, but will not be determined or disclosed until the Full Load Products have been procured.�8 For the reasons given by EPC and the CP, the Board agrees that it would not be appropriate to disclose the risk compensation value until the Full Load Products have been procured. In BR-EPC-2, EPC provided a sample table showing the risk compensation for scenarios where 80%, 85%, 90% and 95% of the full RRT load is hedged by Full Load Products. The Board also notes the following response from EEC in BR-EPC-1:

EEC�s risk compensation, as defined in Section 7 of Appendix 3 of the Energy Price Setting Plan (EPSP) is a $/MWh constant unit value that will be applied to Metered Load, net of the percentage of the Full Load (FL) filled through the FL-RFPs. In the 2004 NS, the energy risk compensation equivalent was $2.73/MWh, which was applied to all metered load.

The Board recognizes that the 2005-2006 NS risk compensation is not directly comparable to the 2004 NS risk compensation of $2.73/MWh. The Board notes that �In the 2005-2006 NS, EEC is at risk for price and volume for the quarter, whereas, in the 2004 NS, EEC was at risk for price and volume for the month.�9 The Board also notes that the �negotiated value of the Energy Risk Compensation is intended to approximate the risk compensation that suppliers of Full Load Products would include in the pricing of those products as compensation for the risks associated with providing a Full Load Product.�10 After review of these factors, the Board is satisfied that the annual11 risk compensation amounts shown in the sample table are reasonable. 8 Application p. 5 9 BR-EPC-1 10 BR-EPC-2 11 Board staff clarified verbally with EPC that the BR-EPC-2 data is annual



Accordingly, for all of the above reasons, the Board approves the NS contained in Appendix A of the Application (Attachment 1). The Board directs EEC to provide the negotiated value of the risk compensation in $/MWh following the completion of the full load RFP(s). The Board also directs EEC to file with the Board, each quarter, the derivation of the Quarterly Energy Rate Calculations as per the provisions of Appendix 3 of the EPSP. 5 ORDER

For and subject to the reasons in this Decision, IT IS HEREBY ORDERED THAT:

1. The Negotiated Settlement attached as Appendix A of the Application (Attachment 1 to this Decision) is approved.

Dated in Calgary, Alberta on October 26, 2004. ALBERTA ENERGY AND UTILITIES BOARD (original signed by) N. W. MacDonald, P.Eng. Presiding Member (original signed by) R. G. Lock, P.Eng. Member (original signed by) J. I. Douglas, FCA Member




ATTACHMENT 1 - NEGOTIATED SETTLEMENT APPLICATION

Negotiated Settlement Application

(Total number of pages including Appendices 62 pages)

In Attachment 1 are the following embedded documents: Appendix A � Terms of Settlement Schedule A Appendix A � Terms of Settlement Schedule B Appendix B � Public Notice Appendix C � Authority to Enter into NSP

2005-2006 Regulated Rate Tariff ENMAX Power Corporation Part C: Energy Price Setting Plan Negotiated Settlement Attachment 1

ENMAX Power Corporation and ENMAX Energy Corporation

2005/2006 Regulated Rate Tariff Energy Price Setting Plan

APPLICATION FOR APPROVAL OF A NEGOTIATED SETTLEMENT

October 15, 2004



Contents

1 INTRODUCTION................................................................................................................ 3

2 VOLUNTARY PARTICIPATION AND RIGHT TO PARTICIPATE......................... 3

3 NOTICE................................................................................................................................ 3

4 INITIATION OF PROCESS .............................................................................................. 3

5 AUTHORITY TO ENTER INTO A NEGOTIATED SETTLEMENT ......................... 4

6 CONFIDENTIALITY ......................................................................................................... 4

7 ROLE OF BOARD STAFF................................................................................................. 4

8 NEGOTIATED SETTLEMENT........................................................................................ 4 8.1 Negotiated Settlement Agreement ................................................................................ 4 8.2 Unresolved Issues ......................................................................................................... 4 8.3 2005�2006 RRT Energy Price Setting Plan................................................................ 5 8.4 Implementation of EEC�s 2005 RRT EPSP.................................................................. 6 8.5 2005 RRT Energy Charge for RCC and NRCC Customers ......................................... 7

9 RELIEF REQUESTED....................................................................................................... 7

APPENDIX A - THE TERMS OF SETTLEMENTAND ENERGY PRICE SETTING PLAN.................................................................................................................. 8

APPENDIX B - PUBLIC NOTICE............................................................................................. 9

APPENDIX C - AUTHORITY TO ENTER INTO A NEGOTIATED SETTLEMENT PROCESS ........................................................................................................ 10



1 INTRODUCTION

In Decision 2004-053, the Alberta Energy and Utilities Board (the �EUB� or �Board�) approved the request of ENMAX Energy Corporation (�EEC�) to commence a negotiated settlement process for its 2005-2006 Regulated Rate Tariff (�RRT�) Energy Price Setting Plan (�EPSP�). EEC entered into discussions with the Consumers� Coalition of Alberta (the �CCA�), the Public Institutional Consumers of Alberta (�PICA�) and the Utilities Consumer Advocate (the �UCA�) (collectively, the �Consultation Parties�). EEC and the Consultation Parties have reached a negotiated settlement with respect to the EPSP to be used in connection with the RRT of ENMAX Power Corporation (�EPC�) for 2005 and the first two quarters of 2006, and have entered into Terms of Settlement (the �Agreement�). A copy of the agreement is attached as Appendix �A� to this application. 2 VOLUNTARY PARTICIPATION AND RIGHT TO PARTICIPATE

In Decision 2004-053, the Board outlined a new requirement for participation in a negotiated settlement process under which a party wishing to participate as an intervener must file with the Board a Request to Participate. In Decision 2004-061, the Board determined which parties were eligible to participate in the negotiated settlement process approved in Decision 2004-053. All parties whose Requests to Participate were approved by the Board in Decision 2004-061 were given the opportunity to participate fully in the negotiated settlement process and have their respective interests properly addressed. Meetings were held between July 22, 2004 and October 14, 2004 in Calgary. Teleconference facilities were available for those parties not able to attend a meeting in person. 3 NOTICE

EEC published a formal Public Notice regarding EEC�s intention to commence negotiations with interested parties in EPC�s service territory with respect to the RRT for January, 2005 through June, 2006. A copy of the notice is provided in Appendix �B.� In this notice, EEC stated that it believed that the main issues to be negotiated were the energy price setting methodology and return margin for risk compensation. This notice was published in the Calgary Herald and the Calgary Sun on July 5, 2004. Additionally, EEC sent the notice by e-mail to interested parties listed on the Board�s distribution list for the 2004 ENMAX/EPCOR Municipal Electric Service Proceeding, as of December 12, 2003. In EEC�s respectful submission, the form and manner of the notice given by EEC conforms to all of the principles governing notice in the Board�s Rules of Practice. 4 INITIATION OF PROCESS

In Decision 2004-053, the Board authorized EEC to commence a negotiated settlement process with respect to the RRT within EPC�s service area for 2005 and 2006.



5 AUTHORITY TO ENTER INTO A NEGOTIATED SETTLEMENT

All of the parties to the Agreement provided proof of their authority to settle issues on behalf of that party, and to enter into a settlement agreement. Copies of the executed documents evidencing authority to enter into a negotiated settlement are set out in Appendix �C.� 6 CONFIDENTIALITY

The negotiated settlement process involved the disclosure and discussion of confidential and commercially sensitive information. As part of the negotiated settlement process, and as provided for in clause 6 of Information Letter IL 98-06 (the Negotiated Settlement Guidelines, (the �Guidelines�)), all parties to the negotiated settlement process agreed to maintain this information in strict confidence and not to use it except for the purposes of the negotiated settlement process and the implementation of the EPSP. EEC�s approach in this regard is consistent with the approach approved by the Board in the past with respect to EPC�s 2004 RRT and with respect to the RRT of other RRT providers, such as EPCOR Energy Services (Alberta) Inc. (�EESAI�). Portions of EEC�s EPSP are also confidential and commercially sensitive, including in particular, the energy procurement protocol and some parts of the rate calculation (Appendices 1, 2 and 3, respectively, of the EPSP). Consequently, the EPSP is being filed in a redacted form without this confidential and commercially sensitive material. This information, the categories of which are identified in Appendix 6 of the EPSP, includes specific pricing parameters, the process for evaluating and accepting RFP Offers and details for determining the energy supply products used for energy price setting. Disclosure of this confidential and commercially sensitive information could adversely affect the acquisition of energy supplies for EPC�s RRT customers. The Consultation Parties have agreed that it is critical that these portions of the EPSP be excluded from the publicly filed version of the EPSP, and the Parties have agreed to a Code of Conduct (including a confidentiality agreement) in relation to this confidential material. This Code of Conduct is set out in Appendix 6 of the EPSP. If the Board believes that disclosure of this confidential and commercially sensitive information is necessary in order to permit the Board to adequately consider this application, ENMAX will seek confidential treatment of this material under rules 12 and 41 of the Boards Rules of Practice. 7 ROLE OF BOARD STAFF

A member of the Board staff was included in the negotiated settlement discussions. 8 NEGOTIATED SETTLEMENT

8.1 Negotiated Settlement Agreement

A copy of the Agreement is attached as Appendix �A�. 8.2 Unresolved Issues

There are no unresolved issues with respect to the 2005-2006 EPSP.



8.3 2005�2006 RRT Energy Price Setting Plan

In this section, capitalized terms not otherwise defined have the meaning set out in the Terms of Settlement, including the EPSP. The Parties have agreed to a comprehensive procurement process involving requests for proposals (�RFPs�) to be held in order to acquire energy for the RRT for all of 2005 and the first two quarters of 2006. The procurement will take place, under the supervision of the Independent Advisor (Jim Joyce of RiskAdvisory, A Division of SAS), and will involve the Third Party Advisor, (Sheldon Fulton, Forte Business Solutions Ltd.), EEC and the Consultation Parties. The goal of the procurement process is to first attempt to fill the RRT load with Full Load Products. A Full Load Product is a financial product that covers a percentage of the actual RRT load, to be settled as a financial swap against the hourly Pool Price with respect to consumed volume plus Unaccounted for Energy and Losses for each applicable hour. If all of the actual RRT load is not filled through the procurement of Full Load Products, additional products will be procured, including Block Load Products � a fixed volume of energy to be settled monthly as a financial swap against the hourly Pool Price for each hour. As required under subsection 5(2) of the Regulated Default Supply Regulation, EEC takes on the procurement risk of acquisition, once the forecast volume and price is agreed to by the Consultation Parties prior to the start of the quarter. The key principles of the EPSP include the following: (a) RRT customers assume price and volume risk, prior to the start of each quarter. (b) EEC assumes all price and volume risk within a quarter. (c) Prior to the start of each quarter, EEC will:

(i) forecast load for the upcoming quarter and the remaining quarters in the Term by hour, including losses and UFE;

(ii) forecast prices for the upcoming quarter and the remaining quarters in the Term by hour, based upon the forward market; and

(iii) forecast a Target Portfolio for each month of the upcoming quarter. (d) Prior to the start of each quarter, the Consultation Parties may, with the agreement of

EEC, substitute some or all of the Product proposed to be purchased by EEC with other products. Alternatively, rather than purchasing replacement products for the Products proposed by EEC, the Consultation Parties may choose to have customers assume price risk in relation to that portion of the load that would have been covered by the proposed Products.

(e) The energy supply for RCC and NRCC customers will be administered as a single pool.

For 2005�2006, the Parties have agreed to use the NERC �west� definition of On Peak Hours (6x16). Accordingly, in order to implement a single energy supply acquisition pool, the parties have agreed that an inter-class price adjustment may be required in order to ensure equity as between RRC and NRRC customers, and EEC has agreed to implement such a price adjustment provided that the implementation of the adjustment is practicable and has no adverse financial impact on EEC.

(f) EEC will assume all counterparty risks.



(g) For staffing and administering of the EPSP, the Parties have agreed that EEC will receive

$0.50 for each MWh of actual metered load. (h) The RFP process will be similar to the RFP process that was used to procure products for

the 2004 RRT. ENMAX Energy Marketing Inc. (EEMI) may be a potential bidder in the RFP rounds. Therefore, a conflict screen will be put in place between ENMAX employees that will participate in the bid and the ENMAX employees that will be procuring the energy through the RFPs. As in the RFP process for the 2004 RRT, qualifying bids will be assigned a letter by the IA, ranked based on price and accepted in accordance with the Procurement Protocol.

(i) EEC will receive a $/MWh risk premium for that portion of the RRT load that is not

covered by Full Load Products. The value of the risk premium will be included in the rate calculation, but will not be determined or disclosed until the Full Load Products have been procured.

(j) EEC has an option to and may supply a limited amount of volume at a price lower than

what would be otherwise procured from third party offers. This option can only be exercised after defined volume has been procured from third parties through RFPs.

(k) EEC will include in the RRT rates its estimated external costs and the estimated costs

associated with the IA, the Third Party Advisor, the Consultation Parties incurred during the negotiation phase, and subsequently, for each quarter. These costs will be submitted to the Board for approval, and to the extent that the costs approved by the Board differ from the estimated costs, the rates will be adjusted to reconcile that difference, as set out in Appendix 3 of the EPSP.

(l) In the second quarter of 2005, an adjustment factor to reconcile initial load settlement and

final load settlement data will be included in the rates for energy acquired in January, February, March, April and May 2004, as directed in Decision 2003-086.

Appendix 5 of the EPSP is intended to set out 2001 to 2004 historic hourly Pool Price indices, gathered from public sources. This information will be compiled when it is required for use by the Parties under the EPSP, and is not being submitted at the present time. The Agreement reflects a number of compromises respecting the different interests of the various parties, and has been negotiated on the basis that the Agreement is contingent on the Board�s accepting the entire Agreement (with the exception of Section 16 of the Terms of Settlement), as permitted under article 12.3 of the Guidelines. 8.4 Implementation of EEC�s 2005 RRT EPSP

In order to have sufficient time to hold an effective efficient RFP process to acquire products with a term commencing on January 1, 2005, the Parties have agreed that the first RFP should be held in early November, 2004. Prior to this time, EEC must also fulfill its forecasting obligations under the Agreement. Consequently, EEC respectfully requests a determination by the Board on an expedited basis.



In order to ensure that the first RFP can be implemented according to the timeline agreed to among the Parties, assuming that the Agreement is approved by the Board, EEC proposes to immediately take the all of the steps required under the Agreement in order to hold the first RFP. No RFPs will be held under the EPSP, however, until the EPSP has been approved by the Board. 8.5 2005 RRT Energy Charge for RCC and NRCC Customers

The Energy Charge will be calculated in accordance with the Rate Calculation set out in Appendix 3 of the EPSP. If the Agreement is approved, EEC will file rates showing the calculation for RCC and NRCC Energy Charges prior to implementing the rates on January 1, 2005. 9 RELIEF REQUESTED ENMAX respectfully requests that the Board approve the Agreement as filed.



APPENDIX A - THE TERMS OF SETTLEMENTAND ENERGY PRICE SETTING PLAN

Terms of Settlement - Schedule A

(Consists of 19 pages)

Terms of Settlement - Schedule B




APPENDIX B - PUBLIC NOTICE

Public Notice

(Consists of 1 page)




APPENDIX C - AUTHORITY TO ENTER INTO A NEGOTIATED SETTLEMENT PROCESS

Authority to Enter into NSP


2005-2006 Regulated Rate Tariff ENMAX Power Corporation Part C: Energy Price Setting Plan Negotiated Settlement Attachment 1 � Appendix A � Schedule A

TERMS OF SETTLEMENT ENMAX ENERGY CORPORATION 2005�2006 REGULATED RATE TARIFF

THESE TERMS OF SETTLEMENT for the negotiated settlement of the Regulated Rate Tariff are made and entered into as of October 15, 2004,

AMONG:

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

and

CONSUMERS� COALITION OF ALBERTA (�CCA�),

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�),

and

UTILITIES CONSUMER ADVOCATE, an office established as part of the Ministry of Government Services by Order in Council 433/2003 (�UCA�),

(CCA, PICA and UCA collectively, the �Consultation Parties�).

WHEREAS:

(a) ENMAX Power Corporation (�EPC�) is responsible under the EUA and the RDS Regulation to provide a Transition Rate to all Eligible Customers;

(b) EPC has appointed EEC to provide Regulated Rate Tariff service in the Service Area;

(c) pursuant to Decision 2004�053, the AEUB approved EEC�s request to commence a negotiated settlement process for its 2005�2006 RRT Energy Price Setting Plan;

(d) EEC, or any other nominee designated by EEC, will conduct certain trades and provide price discovery and other market information; and



(e) EEC and the Consultation Parties have agreed on an electric energy procurement and price setting arrangement with respect to Pool Price and Load exposure in respect of the Target Portfolio for 2005 and the first two Quarters of 2006;

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. Energy Price Setting Plan

The Parties have developed the Energy Price Setting Plan (the �EPSP�), which is attached to and forms a part of these Terms of Settlement. Except as set out in these Terms of Settlement, the EPSP will establish and govern the electric energy procurement and price setting arrangement with respect to Pool Price and Load exposure in respect of the Total Portfolio during the Term.

3. Implementation and Performance of the Energy Price Setting Plan

3.1. The Consultation Parties will:

3.1.1. together with EEC, an independent energy advisor (the �Independent Advisor�) and a third party advisor (the �Third Party Advisor�), implement the EPSP;

3.1.2. perform the obligations of the Consultation Parties under the EPSP, including reviewing Prompt Quarter Final Portfolio Adjustments and proposed acquisitions with EEC, the Independent Advisor and the Third Party Advisor; and

3.1.3. from time to time, designate one (1) representative to act on behalf of each of the Consultation Parties during implementation of the EPSP (the �Representatives�).

3.2. EEC will, and will cause employees, contractors or agents of EEC, as necessary, to be available in order to:

3.2.1. implement the EPSP, together with the Representatives, the Third Party Advisor and the Independent Advisor; and

3.2.2. perform the obligations of EEC under the Energy Price Setting Plan, including:

3.2.2.1. providing forecasts of Load on an hourly basis for each Quarter during the Term, utilizing EEMI forecasting tools;



3.2.2.2. providing forecasts of Pool Prices on an hourly basis based on the forward market for each Quarter during the Term;

3.2.2.3. proposing an acquisition strategy for each Quarter during the Term; and

3.2.2.4. consulting with the Representatives, the Consultation Parties, the Third Party Advisor and the Independent Advisor.

3.3. Subject to Section 7.3, EEC will, or will cause EEMI or any other nominee designated by EEC to enter into the necessary agreements with counterparties, in accordance with the EPSP.

4. Establishment of Hedge Portfolio

4.1. On or before October 18, 2004, EEC will provide to the Consultation Parties for the six (6) Quarters from January 1, 2005 through June 30, 2006, the Forecast Eligible Customer Load (adjusted as may be necessary with respect to 2004 actual Load and any other relevant considerations).

4.1.1. Within two (2) Business Days of receiving the Forecast Eligible Customer Load set out in Section 4.1, the Consultation Parties will deliver to EEC written notice either approving, rejecting or proposing modifications to the Forecast Eligible Customer Load. In the event that the Consultation Parties fail to deliver such written notice within the specified time, the Consultation Parties will be deemed to have accepted the Forecast Eligible Customer Load. In the event that the Consultation Parties reject or propose modifications to the Forecast Eligible Customer Load set out in Section 4.1, EEC and the Consultation Parties will attempt to resolve such dispute.

4.1.2. If EEC and the Consultation Parties cannot agree on the final forecasts set out in Section 4.1.1 within one (1) week of EEC receiving such written notice, then EEC and the Consultation Parties will each provide to the Independent Advisor a written statement setting out its determination of the Forecast Eligible Customer Load. The Independent Advisor must select either EEC�s determination of the Forecast Eligible Customer Load or the Consultation Parties� determination of the Forecast Eligible Customer Load within two (2) Business Days from the date he receives the written statements from EEC and the Consultation Parties.

4.2. Under the supervision of the Independent Advisor, EEC and the Consultation Parties will hold RFPs in order to acquire Products for the Term, consistent with the methodology set out in the EPSP.

5. Forecasting Immediately Prior to Prompt Quarter

5.1. At least thirty-five (35) Business Days in advance of each Prompt Quarter during the Term, EEC will provide to the Consultation Parties the following interim forecasts:



5.1.1. the Load for Eligible Customers for each hour in that Prompt Quarter, net of any Full Load Products acquired, including and identifying any Unaccounted For Energy and Losses for that Prompt Quarter (the �Prompt Quarter Interim Forecast Customer Load�); and

5.1.2. the Pool Price for each hour in that Prompt Quarter based on the forward price and the hourly distribution of Pool Prices for that Prompt Quarter in respect of the Target Portfolio. The forward price will be determined independently using data from third party sources agreed upon by EEC and the Consultation Parties.

5.1.2.1. The hourly Pool Price distribution will be based on:

5.1.2.1.1. the forward price for each month of the Prompt Quarter; and

5.1.2.1.2. the electric energy pricing patterns for each month of the Prompt Quarter, utilizing the previous three (3) year history of the hourly Pool Price distributions for the corresponding Quarter.

5.1.3. An interim Target Portfolio for each month of the Prompt Quarter.

5.2. Within fifteen (15) Business Days of receiving the forecasts set out in Section 5.1, the Consultation Parties may deliver to EEC written notice proposing modifications to the interim forecasts set out in Section 5.1.

5.3. At least ten (10) Business Days in advance of each Prompt Quarter during the Term, EEC will provide the following final forecasts to the Consultation Parties:

5.3.1. the Load for Eligible Customers for each hour in that Prompt Quarter, net of (but indicating) any Full Load Products acquired, including and identifying any Unaccounted for Energy and Losses for that Prompt Quarter (the �Prompt Quarter Final Forecast Customer Load�); and

5.3.2. the Pool Price for each hour in that Prompt Quarter based on the forward price and the hourly distribution of Pool Prices for that Prompt Quarter in respect of the Target Portfolio.

5.3.2.1. The forward price will be determined independently using data from third party sources agreed upon by EEC and the Consultation Parties. The hourly Pool Price distribution will be based on:

5.3.2.1.1. the forward price for each month of the Prompt Quarter; and

5.3.2.1.2. the electric energy pricing patterns for each month of the Prompt Quarter, utilizing the previous three (3) year history of the hourly Pool Price distributions for the corresponding Quarter.

5.3.3. a final Target Portfolio for each month of the Prompt Quarter.



5.4. Within two (2) Business Days of receiving the final forecasts set out in Section 5.3, the Consultation Parties will deliver to EEC written notice either approving, rejecting or proposing modifications to the final forecasts set out in Section 5.3. In the event the Consultation Parties fail to deliver such written notice within the specified time, the Consultation Parties will be deemed to have accepted the final forecasts set out in Section 5.3. In the event that the Consultation Parties reject or propose modifications to the final forecasts set out in Section 5.3, EEC and the Consultation Parties will attempt to resolve such dispute.

5.5. If EEC and the Consultation Parties cannot agree on the final forecasts set out in Section 5.3 within one (1) Business Day of EEC receiving such written notice, then EEC and the Consultation Parties will each provide to the Independent Advisor a written statement setting out its determination of the final forecasts set out in Section 5.3. The Independent Advisor must select either EEC�s determination of the final forecasts set out in Section 5.3 or the Consultation Parties� determination of the final forecasts set out in Section 5.3 within two (2) Business Days from the date he receives the written statements from EEC and the Consultation Parties.

6. Forecasting for Quarters following Prompt Quarter

6.1. At least thirty-five (35) Business Days in advance of each Prompt Quarter during the Term, EEC will:

6.1.1. forecast the Load for Eligible Customers for each hour in any or all of the Quarters remaining in the Term, net of any Full Load Products acquired, identifying any Unaccounted for Energy and Losses for those Quarters; and

6.1.2. forecast the Pool Price for each hour in any or all of the Quarters remaining in the Term based on the forward price and the hourly distribution of Pool Prices for those Quarters in respect of the Target Portfolio.

6.1.2.1. The forward price will be determined independently using data from third party sources agreed upon by EEC and the Consultation Parties. The hourly Pool Price distribution will be based on:

6.1.2.1.1. the forward price for each month of the Quarter; and

6.1.2.1.2. the electric energy pricing patterns for each month of the Prompt Quarter utilizing the previous three (3) year history of the hourly Pool Price distributions, for the corresponding quarter.

6.1.3. forecast a Target Portfolio for each Month of the Quarter.

7. Acquisition of Products for Target Portfolio

7.1. EEC will acquire products for the Target Portfolio according to the protocol set out in Appendix 2 of the EPSP.



7.2. For each hour in a Prompt Quarter, the �Prompt Quarter Final Forecast Portfolio Adjustment� will be determined as follows:

[Prompt Quarter Final Forecast Customer Load-(Volume of Hedging Agreements acquired + final Target Portfolio)] x forecasted Pool Price for that hour (as determined in Section 6.1.2)

If the Prompt Quarter Final Forecast Portfolio Adjustment is a positive amount, Eligible Customers will pay that amount to EEC. If the Prompt Quarter Final Forecast Portfolio Adjustment is a negative amount, EEC will refund that amount to Eligible Customers.

7.3. The Consultation Parties may, within the Target Portfolio determined in Section 5.3.3, elect to:

7.3.1. buy or sell any Hedging Agreements; or

7.3.2. enter into an Alternative Hedge with respect to any Hedging Agreements.

8. Acquisition of Hedging Agreements for Quarters following Prompt Quarter

Subject to Section 6, and with the prior consent of the Consultation Parties, in accordance with the Energy Price Setting Plan, EEC may buy or sell Block Load Products for any or all of the Quarters remaining in the Term.

9. Pool Price and Load Exposure of EEC and Customers

9.1. As set out in more detail in the EPSP, for each Supply Quarter, Eligible Customers will be responsible for paying to EEC for each hour in that Supply Quarter an amount based upon the procurement price of all Products acquired and the Prompt Quarter Final Forecast Portfolio Adjustment.

9.2. Subject to Section 7.2, and as described in more detail in the EPSP, for each hour in a Supply Quarter, the following will be for EEC�s account:

9.2.1. any settlements for Pool Price with respect to Hedging Agreements and Full Load Products; and

9.2.2. any variance based upon the difference between actual Load net of the Volume of all Full Load Products acquired for Eligible Customers (including any Unaccounted for Energy and Losses ) and the Forecast Eligible Customer Load , to the extent of the difference between the Pool Price and the procurement price of the Hedging Agreements and the Prompt Quarter Final Forecast Portfolio Adjustment.

9.3. EEC will be responsible for all risks and liabilities associated with the creditworthiness of counterparties to the Hedging Agreements and the Full Load Products; provided that EEC will be compensated for assuming these risks and



liabilities in the non-energy margin compensation as may be determined by the AEUB.

10. Rate Class Adjustment

In the event that the Consultation Parties agree that an inter-class adjustment is required in order to ensure equity as between RCC and NRCC customers, EEC agrees that it will implement such an adjustment as agreed to by the Consultation Parties, provided that the implementation of the adjustment is practicable and has no adverse financial impact on EEC.

11. Rates

11.1. EEC will estimate and set the rates payable by Eligible Customers for electric energy supplied by EEC each Quarter during the Term in accordance with the Energy Price Setting Plan, which will include the costs set out in Section 12 and any other rate riders and charges as determined from time to time by the AEUB (the �Filed Rate�) by:

11.1.1. December 23, 2004 for Q1 2005;

11.1.2. March 24, 2005 for Q2 2005; for

11.1.3. June 24, 2005 for Q3 2005;

11.1.4. September 26, 2005 for Q4 2005;

11.1.5. December 23, 2005 for Q1 2006; and

11.1.6. March 27, 2006 for Q2 2006.

(the �Filing Dates�).

11.2. Ten (10) Business Days prior to the Prompt Quarter, EEC will provide to the Consultation Parties the Filed Rate for that Filing Date. EEC will file the Filed Rate with the AEUB prior to the applicable Filing Date. In the event of a dispute between EEC and the Consultation Parties regarding the Filed Rate, the dispute will be resolved by the AEUB on the basis of written submissions to be filed by EEC and the Consultation Parties within three (3) Business Days after the applicable Filing Date.

11.3. Any adjustments arising as a result of reconciliation of initial and final settlement data will be made in the Filed Rate of the following fiscal quarters.

12. Costs to be Included in Rates

12.1. EEC will recover from Eligible Customers, and Eligible Customers will pay to EEC, the following amounts during the Term:



12.1.1. an energy rate calculated in accordance with, and including those fees and charges set out in Appendix 3 of the EPSP for each Quarter during the Term;

12.1.2. Hedge Costs and Trading Costs for each Quarter during the Term;

12.1.3. Estimated costs and expenses of the Independent Advisor, the Third Party Advisor and the Consultation Parties related to the development and implementation of these Terms of Settlement and the EPSP, based upon invoices submitted to EEC, provided that once the AEUB has issued a cost order in relation to these costs and expenses, the rates will be adjusted as necessary to ensure that the recovery of costs and expenses through the rates does not exceed the costs and expenses approved by the AEUB.

12.1.4. Forecast third party costs and expenses incurred by EEC in relation to the development of these Terms of Settlement and the EPSP, including consultants and external legal fees and disbursements, provided that once the AEUB has issued a cost order in relation to these costs and expenses, the rates will be adjusted as necessary to ensure that the recovery of costs and expenses through the rates does not exceed the costs and expenses approved by the AEUB.

13. Representations and Warranties

13.1. Each of the Consultation Parties represents and warrants to EEC that:

13.1.1. it is duly organized, validly existing and in good standing under the laws of the jurisdiction of its formation;

13.1.2. its membership or constituents include Eligible Customers within the Service Area; and

13.1.3. it has not withheld any relevant information.

13.2. EEC represents and warrants to the Consultation Parties that:

13.2.1. it is duly organized, validly existing and in good standing under the laws of the jurisdiction of its formation; and

13.2.2. it has not withheld any relevant information.

14. Support of Terms of Settlement

The Consultation Parties will support the application by EEC to the AEUB for approval of these Terms of Settlement and the Energy Price Setting Plan.

15. AEUB Approval



15.1. Subject to Section 15.2, unless otherwise agreed to by the Parties in writing, if the AEUB declines to approve these Terms of Settlement and the Energy Price Setting Plan in their entirety, these Terms of Settlement will be of no force and effect.

15.2. Section 15.1 does not apply to Section 16.

16. Stranded Costs

Notwithstanding any other provision of these Terms of Settlement, if a Party reasonably believes that costs that cannot reasonably be recovered from remaining Eligible Customers through just and reasonable RRT rates (�Stranded Costs�) may be caused by the departure of Eligible Customers from RRT service, that Party may bring an application to the AEUB for the recovery of the Stranded Costs, and those Stranded Costs will be dealt with in a manner to be determined by the AEUB.

17. Term

Subject to Section 15, and unless agreed to by the Parties in writing and approved by the AEUB, these Terms of Settlement will commence upon approval of these Terms of Settlement and the Energy Price Setting Plan by the AEUB and will terminate at 11:59 p.m. on June 30, 2006 (the �Term�); provided, however, that any obligation to make payment in accordance with any adjustments pursuant to these Terms of Settlement or the Energy Price Setting Plan will survive the termination of these Terms of Settlement. All final adjustments to rates must be completed no later than the date the regulated rate tariff for electric energy rates is filed with the AEUB for the second quarter of 2007.

18. Costs and Expenses of Consultation Parties, the Independent Advisor and the Third Party Advisor

18.1. Within thirty (30) days following the receipt of invoices from the Independent Advisor, the Third Party Advisor and the Consultation Parties, EEC will pay the costs and expenses incurred by the Independent Advisor, the Third Party Advisor and the Consultation Parties in respect of the negotiation, development and the application to the AEUB for approval of these Terms of Settlement and the EPSP.

18.2. EEC will be responsible for preparing and submitting cost claims to the AEUB in respect of the costs and expenses referred to in Section 18.1.

18.3. In the event that the costs and expenses of the Third Party Advisor and the Consultation Parties approved by the AEUB are less than the amount paid to a party under Section 18.1, that party must, within thirty (30) days of the date that the AEUB issues the relevant cost order, pay to EEC the amount by which the payment made under Section 18.1 exceeds the amount approved by the AEUB.

19. Without Prejudice

These Terms of Settlement and the Energy Price Setting Plan are agreed to without prejudice to the position of the Parties in subsequent negotiations and regulatory proceedings.



20. Miscellaneous

20.1. Where a term is defined in these Terms of Settlement, a capitalized derivative of such term will have a corresponding meaning unless the context otherwise requires. In these Terms of Settlement, references to:

20.1.1. Sections are to sections in or to these Terms of Settlement, unless otherwise stated;

20.1.2. Schedules are to schedules attached to these Terms of Settlement, each of which is hereby 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

20.1.3. �including� means �including, without limitation,� and �includes� and other derivatives thereof will have corresponding meanings.

20.2. 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. In these Terms of Settlement, words importing the singular will include the plural and vice versa. Any reference to a statute is a reference to it as re-enacted, varied, amended, modified, supplemented or replaced from time to time. 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. Unless otherwise noted in these Terms of Settlement, all items of revenue, expense, cost, gain, loss, liability or disposition proceeds and all determinations with respect to accruals and all accounting matters or terms in these Terms of Settlement will be determined or construed in accordance with generally accepted accounting principles in Canada.

20.3. 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 between the Parties. The Consultation Parties will not assign these Terms of Settlement without the prior written consent of EEC; 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.

20.4. Any notice or other communication from one Party to the other Party 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 it at:

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

Attention: Gordon Edwards Facsimile: (403) 515-3505 E-mail: [email protected]

with an e-mail copy to:

Chris Devasahayam at: [email protected]

if to CCA addressed to it at:

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]

if to PICA, addressed to it at:

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 it at:

Utilities Consumer Advocate TD Tower 1701, 10088 � 102 Avenue Edmonton, AB T5J 2Z1

Attention: David Gray Facsimile: (780) 644-5129 E-mail: [email protected]

20.5. 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 20.4.

20.6. 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.

20.7. 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.

20.8. Subject to Section 15 and except as otherwise set out in these Terms of Settlement, in the event that any of the provisions of these Terms of 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.

20.9. 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.

20.10. Time will be of the essence in respect of these Terms of Settlement.

20.11. 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:

UTILITIES CONSUMER ADVOCATE PUBLIC INSTITUTIONAL CONSUMERS OF ALBERTA

Per: Per Name:

Title:

Name: Title:



SCHEDULE �A�

DEFINITIONS

The following terms have the meanings set out below:

�AESO� means the �Independent System Operator� as defined in the EUA, currently the Alberta Electrical System Operator;

�Alternative Hedge� has the meaning set out in Section 9 of Appendix 2 of the EPSP;

�AEUB� means the Alberta Energy and Utilities Board;

�Balance of Year Product� means a hedge product consisting of all Months to the end of the year;

�Baseload� means all hours, or 7x24;

�Baseload Product� means a hedge product that notionally delivers electric energy over all hours (7x24);

�Block Load� or �BL� means a Baseload or On-peak fixed volume for a term of one month, one quarter or one calendar year;

�Block Load Product� means a product that covers all or a portion of the Block Load;

�Board Observer� means the individual designated by the AEUB to observe and assist as provided in the Energy Price Setting Plan;

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

�Certification of Compliance� means, in relation to Procurement, a certification that EEC has carried out the Procurement in compliance with the Energy Price Setting Plan, in the form attached as Appendix 4 to the Energy Price Setting Plan, subject to the applicable comments from the Independent Advisor, the Parties and the Designated Trader;

�Consultation Parties� has the meaning set out in the recitals to the Terms of Settlement;

�Decision 2004�053� means AEUB Decision 2004�053 (2005�2006 Regulated Rate Tariff Energy Application: Request for Approval to Commence a Negotiated Settlement for an Energy Price Setting Plan) dated June 29, 2004;

�Designated Trader� has the meaning set out in Appendix 2 to the Energy Price Setting Plan;



�EEC� means ENMAX Energy Corporation, and includes its nominees;

�EEMI� means ENMAX Energy Marketing Inc.;

�Eligible Customers� means RCC Customers and NRCC Customers;

�Energy Portfolio Prices� means, for a Quarter, the prices of all Products acquired;

�Energy Price Setting Plan� or �EPSP� means the Energy Price Setting Plan developed in accordance with the Terms of Settlement and attached as Schedule B to the Terms of Settlement;

�Energy Product Portfolio� means, at a point in time, the portfolio of Products that have then been acquired or deemed to have been acquired for the Energy Product Portfolio pursuant to the Energy Price Setting Plan and the terms of which have not expired at that time;

�Energy Rate Calculation� means the Energy Rate Calculation attached as Appendix 3 to the Energy Price Setting Plan;

�Energy Risk Compensation� has the meaning set out in Section 7 of Appendix 3 of the EPSP;

�EPC� means ENMAX Power Corporation;

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

�Exchange� means the online trading systems in Alberta operated by (i) Alberta Watt Exchange Limited, or (ii) Natural Gas Exchange Inc.;

�Exchange Screen� means the trading system operated by an Exchange;

�Filed Rates� has the meaning set out in Section 11 of the Terms of Settlement;

�Filing Dates� has the meaning set out in Section 11 of the Terms of Settlement;

�Firm RFP Offers� has the meaning set out in Section 2.2.2 of Appendix 2 of the EPSP;

�Forecasted Customer Metered Load� means the Prompt Quarter Final Forecast Customer Load, not including any Unaccounted for Energy and Losses;

�Forecasted NRCC Customer Metered Load� means that portion of the Forecasted Customer Metered Load applicable to NRCC Customers;

�Forecasted RCC Customer Metered Load� means that portion of the Forecasted Customer Metered Load applicable to RCC Customers;



�Forecast Eligible Customer Load� means the forecast of NRCC Customer and RCC Customer Loads, net of (but indicating) any Full Load Products acquired, over each Quarter for each hour in each Month of that Quarter, including any unaccounted for electric energy and losses;

�Forecast Monthly Price� is the price calculated in Section 1 of Appendix 7 of the EPSP;

�Forecast NRCC Customer Load� means that portion of the Forecast Eligible Customer Load applicable to NRCC Customers;

�Forecast RCC Customer Load� means that portion of the Forecast Eligible Customer Load applicable to RCC Customers;

�Full Load� or �FL� means the actual RRT Load, with a volume that may vary in each hour, including Unaccounted for Energy and Losses;

�Full Load Portfolio Price� means weighted average price of all Full Load Products acquired;

�Full Load Product� means a product that covers a percentage of the Full Load, to be settled as a financial swap against the hourly Pool price with respect to consumed volume plus Unaccounted for Energy and Losses for each applicable hour;

�Hedge Costs� means all verifiable costs associated with the procurement of Hedging Agreements and Full Load Products;

�Hedged Price� means the weighted average price for all Hedging Agreements, in respect of a Supply Quarter;

�Hedging Agreements� means all financial agreements and transactions, whether exchange based or over-the-counter, entered into by EEC, EEMI or any other nominee designated by EEC for the purpose of hedging Eligible Customers� Pool Price and Load exposure, but does not include Full Load Products;

�Independent Advisor� is the person referred to in Section 3.1.1 of the Terms of Settlement, appointed with the agreement of the Parties;

�Independent System Operator� has the meaning set out in the EUA;

�Load� means the consumption of electric energy for a given time period and for a specified group of consumers as measured through metering devices, including any Unaccounted for Energy and Losses;

�Metered Load� means Load, net of Unaccounted for Energy and Losses;

�Month� means the period beginning at 12:00:00 a.m. on the first day of a calendar month and ending at 11:59:59 p.m. on the last day of the calendar month, and a reference



to any particular month means the period beginning at 12:00:00 a.m. on the first day of that month and ending at 11:59:59 p.m. on the last day of that month;

�Monthly Product� means a Monthly Base Product or a Monthly On-peak Product;

�Monthly Baseload Product� means a Baseload Product having a one-Month term;

�Monthly On-peak Product� means an On-peak Product having a one-Month term;

�MW� means megawatts;

�MWh� means megawatt hours;

�NGX� means Natural Gas Exchange, Inc.;

�NRCC Customers� means non-rate classification customers, being all customers of EPC in the Service Area, other than RCC Customers and those customers served through a contract with a third party supplier, for whom the forecasted annual consumption of electric energy at a site is less than two hundred and fifty (250) megawatt hours of electric energy;

�NYMEX� means the New York Mercantile Exchange;

�Off-peak Hours� means the hours which are not On-peak Hours;

�On-peak Hours� means the NERC �west� definition of on-peak hours;

�On-peak Product� means a hedge product that notionally delivers electric energy over all On-peak Hours;

�One-Year Baseload Product� means a Baseload Product having a one-year term;

�One-Year On-peak Product� means an On-peak Product having a one-Year term;

�One-Year Product� means a One-Year Base Product and a One-Year On-peak Product;

�Parties� means EEC, CCA, PICA and UCA, and �Party� means any one of them;

�Pool Price� means the price established and reported by the Independent System Operator for electric energy exchanged through the Power Pool;

�Power Pool� has the meaning set out in the EUA;

�Procurement� means the process administered by the Independent Advisor and conducted in accordance with Appendix 2;

�Procurement Protocol� means the Procurement Protocol attached to the Energy Price Setting Plan as Appendix 2;



�Product� means a Baseload Product, an On-peak Product, a Block Load Product or a Full Load Product;

�Prompt Quarter� means the Quarter beginning immediately after the current Quarter;

�Prompt Quarter Final Forecast Customer Load� has the meaning set out in Section 5.3.1 of the Terms of Settlement;

�Prompt Quarter Final Forecast Portfolio Adjustment� has the meaning set out in Section 7.2 of the Terms of Settlement;

�Prompt Quarter Interim Forecast Customer Load� has the meaning set out in Section 5.1.1 of the Terms of Settlement;

�Quarter� means a period of three (3) consecutive Months;

�Q1 2005�means January, February and March, 2005;

�Q2 2005� means April, May and June, 2005;

�Q3 2005�means July, August and September, 2005;

�Q4 2005�means October, November and December, 2005;

�Q1 2006� means January, February and March, 2006;

�Q2 2006� means April, May and June, 2006;

�Quarterly Baseload Product� means a Baseload Product having a one Quarter term;

�Quarterly On-peak Product� means a On-peak Product having a one Quarter term; and

�Quarterly Product� means a Quarterly Baseload Product and a Quarterly On-peak Product;

�Quarterly Product Schedule� means a schedule for the Quarter in the applicable form attached as Appendix 2 to the Energy Price Setting Plan setting out, among other things, the Total Portfolio, Target Portfolio, and the Existing Portfolio based on the forecast electric energy consumption at the customer meter for each Month of the Quarter;

�RDS Regulation� means the Regulated Default Supply Regulation, A.R. 168/2003;

�Remaining Load� means, at any time, the difference between the Forecast Eligible Customer Load and the Volume of the Hedging Agreements;

�Regulated Rate Tariff� has the meaning set out in the RDS Regulation;



�Representatives� has the meaning set out in Section 3.1 of the Terms of Settlement;

�RFP� means a request for proposal process, and includes all of the request for proposal processes used to acquire Products under the EPSP, and the duration of any RFP extends from the time an RFP Notice is sent to Suppliers until the RFP ends in accordance with the provisions of Appendix 2 of the EPSP;

�RFP Notice� has the meaning set out in Section 2.2.2 of Appendix 2 of the EPSP;

�Round� means the period beginning with the receipt of the Prompt Quarter Interim Forecast Customer Load for the Prompt Quarter and ending on the last Business Day of the second Month of the Supply Quarter;

�RCC Customers� means the rate classification customers of EPC in the Service Area, other than those customers served through a contract with a third party supplier;

�RRT� means a regulated rate tariff as contemplated under Section 103 of the EUA;

�RRT Transition Rate� means a regulated rate tariff for Eligible Customers approved by the AEUB under the Section 103 of the EUA;

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

�Submission Date� means, with respect to any RFP, the date set out in the respective RFP Notice by which all offers must be received by the Independent Advisor;

�Supplier� has the meaning set out in Section 2.2.1 of Appendix 2 of the EPSP;

�Supply Quarter� means a Quarter in which electric energy is supplied to Eligible Customers during the Term, provided that the first Supply Quarter will be Q1 2005;

�Target Portfolio� means the Total Portfolio, net of Full Load Products and Hedging Agreements;

�Term� has the meaning set out in Section 17 of the Terms of Settlement;

�Terms of Settlement� means the Terms of Settlement for the negotiated settlement of the Regulated Rate Tariff, including the recitals and the Schedules attached to the Terms of Settlement;

�Third Party Advisor� is the person referred to in Section 3.1.1 of the Terms of Settlement, who is nominated by the Consultation Parties and consented to by EEC, which consent may not unreasonably be withheld and who, once appointed, takes instructions from the Consultation Parties;




�Total Portfolio� means the aggregate of Full Load Products, Baseload Products and On-peak Products required for each Quarter during the Term, based on Forecast Eligible Customer Load, and the formula set out in Section 5.3.4 of Appendix 2 to the EPSP;

�Total Portfolio Load� means the product of the Prompt Quarter Final Forecast Customer Load and the difference between 100 and the percentage of Full Load filled through the acquisition of Full Load Products;

�Trading Costs� means all verifiable costs associated with the act of trading of electricity, and includes brokerage and exchange fees; and

�Transition Rate� has the meaning set out in the RDS Regulation.

�Unaccounted for Energy and Losses� means, at any particular time, the most recent data provided by EPC in respect of unaccounted for electric energy and line losses, expressed as a percentage of Load; and

�Volume� means:

(a) in respect of a BL Product or BL�RFP, a specific number of MW; and

(b) in respect of an FL Product or FL�RFP, a specific percentage of the Full Load.

2005-2006 Regulated Rate Tariff ENMAX Power Corporation Part C: Energy Price Setting Plan Negotiated Settlement Attachment 1 � Appendix A � Schedule B

ENMAX ENERGY CORPORATION 2005�2006 ENERGY PRICE SETTING PLAN

October 15, 2004

1. Definitions

Capitalized terms used in this Energy Price Setting Plan, that are not otherwise defined herein, have the respective meanings ascribed to those terms in Schedule �A� to the Terms of Settlement. 2. RRT Transition Rate Electric Energy Cost

2.1. The electric energy cost component of EEC�s RRT Transition Rate will be determined on the basis of the Full Load Products, Hedging Agreements and Prompt Quarter Final Forecast Portfolio Adjustment, including any Alternative Hedges, utilizing the procedures set out in the Energy Rate Calculation in Appendix 3.

2.2. The RRT rates for electric energy to be paid to EEC by Eligible Customers on Metered Load will be determined in accordance with the Energy Rate Calculation attached to this EPSP as Appendix 3.

3. Energy Product Portfolio

3.1. The Energy Product Portfolio will be procured in accordance with the provisions of Appendix 2 of this EPSP.

3.2. The Quarterly Product Schedule will be determined in accordance with the Terms of Settlement and the procedure set out in Appendix 1. Monthly Products required in advance of the Prompt Quarter may be acquired as Quarterly Products, as set out in Appendix 1.

4. Code of Conduct

The Code of Conduct attached to the Energy Price Setting Plan as Appendix 6 will govern the use of commercially sensitive information related to this Energy Price Setting Plan and the Terms of Settlement.

5. Representation during RFPs and Rounds

RFPs and Rounds are dynamic processes where it is essential to be able to make decisions in a timely and efficient manner to respond to changing circumstances. EEC and the Representatives will be available during each RFP and Round and, working with the Independent Advisor and the Third Party Advisor, will have authority to agree to modifications to the Procurement Protocol as necessary to respond to particular circumstances that may arise during an RFP or Round with the objective of reducing Energy Portfolio Prices. If, during an RFP or Round, EEC and the Representatives do not agree on a particular modification, the RFP or Round will continue without modification.



6. Certification following RFPs and Rounds

6.1. Upon the request of the AEUB, EEC will prepare and circulate to the Representatives and the Independent Advisor, a Certification of Compliance in the form set out in Appendix 4 for a Round certifying, subject to applicable comments, that EEC has carried out that Round in compliance with the requirements of this Energy Price Setting Plan.

6.2. Upon the request of the AEUB, the Independent Advisor will prepare and circulate to the Representatives and EEC, a Certification of Compliance in the form set out in Appendix 4 for an RFP certifying, subject to applicable comments, that EEC has carried out that RFP in compliance with the requirements of this Energy Price Setting Plan.

7. Consultation Process between RFPs and Rounds

EEC and the Representatives will meet with the Independent Advisor within two (2) Business Days or such other time as they may agree following the end of each RFP session and each Round. The Representatives, the Independent Advisor and the Third Party Advisor will review the results of the RFP or Round and any market developments or trends that any party may reasonably believe will have a material impact on the continued implementation of this Energy Price Setting Plan. This could include, but is not limited to, significant changes in market prices or EEC RRT Transition Rate Load requirements. At the request of either party, EEC and the Representatives will work in good faith to identify any improvements that can be made to the Procurement Protocol taking into account the matters discussed above. EEC and the Representatives will work diligently to agree on any amendments to the Procurement Protocol that may be necessary to implement the identified improvements.

8. Dispute Resolution

8.1. If EEC and the Representatives are unable to agree under Section 7 as to whether any improvements need to be made to the Protocol or on any amendments necessary to implement any identified improvement, either EEC or the Consultation Parties (the �Disputing Party�) may at any time invoke the dispute resolution process (the �Dispute Resolution Process�) under this Section by providing a written notice (the �Dispute Notice�) to the other party, the Independent Advisor and Board Observer. The Dispute Notice must:

8.1.1. identify the specific change that is proposed (the �Proposed Change�) and the impact the Proposed Change would reasonably be expected to have on RRT rates, if any; and

8.1.2. identify the reason for the Proposed Change and the harm that would reasonably be expected to occur if the Proposed Change is or is not made, as the case may be.



8.2. EEC, the Consultation Parties, the Independent Advisor and the Board Observer will use their best efforts to meet to discuss the Proposed Change within two (2) Business Days of the Dispute Notice being provided. At that meeting, the Disputing Party invoking the Dispute Resolution Process will cooperate fully by answering any questions that other party (the �Other Party�), the Independent Advisor or the Board Observer may have respecting the Proposed Change and EEC and the Consultation Parties will work diligently and in good faith to reach agreement concerning the Proposed Change.

8.3. If no agreement is reached at the meeting provided for under Section 8.2, the Disputing Party must provide written notice (the �Election Notice�) to the Other Party, the Independent Advisor and the Board Observer within one (1) Business Day of the conclusion of the meeting if it wishes to continue the Dispute Resolution Process.

8.4. If the Disputing Party elects to continue the Dispute Resolution Process under Section 8.3, the Other Party may provide written notice (the �Continuation Notice�) to the Disputing Party within one (1) Business Day of receiving the Election Notice advising the Disputing Party whether it agrees to continue the Dispute Resolution Process.

8.5. If the Disputing Party does not provide the Election Notice as provided under Section 8.3, or if the Other Party provides a Continuation Notice advising that it does not agree to continue the Dispute Resolution Process or does not provide the Continuation Notice under Section 8.4, the Disputing Party will be free to pursue the Proposed Change with the AEUB, provided that the Disputing Party must ask the AEUB to decide the matter on an expedited basis and respect the confidential nature of the matters to be addressed to the extent permitted under the AEUB�s Rules of Practice.

8.6. If the Other Party agrees to continue the Dispute Resolution Process under Section 8.4, then both the Disputing Party and the Other Party will submit a final proposal (the �Final Proposal�) in respect of the matters addressed in the Dispute Notice, to each other, the Independent Advisor and the Board Observer within one (1) Business Day of the Continuation Notice being provided. Any Final Proposal submitted must include the information required to be included in the Dispute Notice. If a party elects not to provide a Final Proposal within the allowed time, the Independent Advisor and the Board Observer will proceed to resolve the matter based on the Final Proposal provided by the other party.

8.7. After considering the Final Proposal(s) submitted, the Independent Advisor and the Board Observer, within two (2) Business Days of the Final Proposal(s) being submitted, must select one of the following options, with written reasons:

8.7.1. decide that no change should be made to this Energy Price Setting Plan;



8.7.2. decide in favour of EEC�s Final Proposal, if submitted; or

8.7.3. decide in favour of the Consultation Parties� Final Proposal, if submitted.

The Independent Advisor and Board Observer will select the option that is not inconsistent with the intent of EEC and the Consultation Parties as reflected in this Energy Price Setting Plan and the Terms of Settlement.

8.8. If the Independent Advisor and Board Observer both select either EEC�s or the Consultation Parties� Final Proposal, then this Energy Price Setting Plan will be amended in accordance with that Final Proposal. If the Independent Advisor and the Board Observer select different Final Proposals, then no change will be made to this Energy Price Setting Plan.

8.9. The decision of the Independent Advisor and the Board Observer under Section 8.8 concerning the Proposed Changes to this Energy Price Setting Plan is final and binding on both EEC and the Consultation Parties and may not be appealed by either party to the AEUB.

8.10. All of the material provided by a party and positions taken by a party throughout the Dispute Resolution Process are confidential and may not be disclosed by any other party without the written consent of that party.

9. Appendices

The following appendices are attached to, incorporated by reference in and form part of this Energy Price Setting Plan:

Appendix 1 Quarterly Product Schedules for 2004

Appendix 2 Procurement Protocol

Appendix 3 Energy Rate Calculation

Appendix 4 Certification of Compliance

Appendix 5 October, 2001 to September, 2004 Historic Hourly Pool Price Indices

Appendix 6 Code of Conduct

Appendix 7 Determination of Forecast Quarterly Price and Forecast Eligible Customer Load



Appendix 1 to the 2005�2006 Energy Price Setting Plan

dated October 15, 2004

Redacted - Confidential





Redacted - Confidential





ENERGY RATE CALCULATION

The Energy Rate Calculation will be based on Quarterly electric energy pricing and will establish a Quarterly RRT rate. The Quarterly electric energy price will be established based on procurement, sales and adjustments for each Month of the Quarter. Except as set out herein, capitalized terms used in this Energy Rate Calculation will have the meanings set out in Schedule �A� to the Terms of Settlement and Schedule �A� to Appendix 2 of the Energy Price Setting Plan.

1. Quarterly Rate Methodology

The �Monthly Energy Price� will be expressed in dollars per MWh and will be used in setting the Quarterly Rate set out in Section 9, which in turn will be applied to actual electric energy delivered to Eligible Customers. The Quarterly Rate will be the weighted average of the three Monthly Energy Prices in the respective Quarter plus Settlement Costs (determined in Section 6), ∆ Settlement Costs (as set out in Section 10), Power Pool Trading Charges, and the Administrative Charges (determined in Section 8). The rate will be adjusted for RCC and NRCC customer classes in accordance with Section 10. The Monthly Energy Price will be determined as follows:

Monthly Energy Pricei = ((FL% x FLP Price) / (1-UFE&L) + FL Hedge Procurement Costs ) + (Hedged Pricei + Energy Risk Compensation + Prompt Quarter Final Forecast Portfolio Adjustment Per MWh + RFP Performance Payment ) x (1 � FL%)

where:

�FL%� means the percentage of the Full Load filled through the FL�RFPs. �FLP Price� means the weighted average price of all Full Load Products acquired. �FL Hedge Procurement Costs� means the actual and verifiable brokerage fees, collateral costs and other costs and expenses associated with the Procurement of the Full Load electric energy, divided by Forecasted Customer Metered Load for each Supply Month. �Prompt Quarter Final Forecast Portfolio Adjustment� means the amount calculated in accordance with Section 5. �UFE&L� means the average Unaccounted for Energy and Losses for the last 12 months, expressed as a percentage, and determined using final Settlement data provided by EPC. �RFP Performance Calculation� means the RFP Performance Calculation calculated in accordance with Section 7 of Appendix 2 of the EPSP, net of the percentage of the Full Load filled through the FL-RFPs.



2. Hedged Price

The �Hedged Price� will be determined as follows:

Hedged Price =

(Hedge Purchases � Hedge Sales)

3. Hedge Purchases

The �Hedge Purchases� will be determined as follows:

n Σ i=0

Hedge Purchases =

((Hedge Volume Procuredi) x (Hedge Purchase Pricei) x (Number of Hours Defined by the Hedgei)) + Hedge Procurement Costs

Forecasted Customer Metered Load for each Supply Month x (1�FL%)

where:

�n� is the number of Hedging Purchases for that Month. �Hedge Volume Procured� is defined as the number of MW acquired during Procurement. �Number of Hours Defined by the Hedge� is determined by the Product purchased for Eligible Customers for the Prompt Month. In the event that a multiple Month or a forward Product is purchased, these hours will be included in the calculation for the appropriate Month�s price taking into consideration any necessary adjustments for weekend and holidays defined by the Product purchased. �Hedge Procurement Costs� means the Monthly proportionate share of all costs associated with purchasing the required hedge volumes not outlined by the Settlement Costs plus any adjustments for procurement incentives, incurred in the previous Supply Quarter. This will include actual and verifiable brokerage fees, collateral costs and other costs and expenses associated with the Procurement of this electric energy. �Hedge Purchase Price� is the transaction price for the hedges.



4. Hedge Sales

The �Hedge Sales� will be determined as follows:

Hedge Sale =

n Σ

I=0

[(abs (Hedge Volume Soldi)) x (Sale Pricei)x(Number of Hours Defined by the Hedgei)]� Hedge Sale Costs

Forecasted Customer Metered Load for each Supply Month x (1�FL%)

where:

�abs� means the absolute value. �n� is the number of Hedge Sales for that Month. �Hedge Volume Sold� is defined as the number of MW sold in the hedge sale process. �Number of Hours Defined by the Hedge� is determined by the Product sold for Eligible Customers for the next Month. In the event that a multiple Month or a forward Product is sold, these hours will be included in the calculation for the appropriate Month�s revenue taking into consideration any necessary adjustments for weekend and holidays defined by the Product sold. �Hedge Sale Costs� include all costs associated with the sale of the required hedge Load not outlined by the Settlement Costs plus any adjustments for procurement incentives, incurred in the previous Supply Quarter. This may include actual and verifiable brokerage fees and other costs associated with the sale of this electric energy. �Sale Price� is the selling price for the hedge in MWh.

5. Prompt Quarter Final Forecast Portfolio Adjustment Per MWh

The �Prompt Quarter Final Forecast Portfolio Adjustment Per MWh� will be determined as follows: Prompt Quarter Final Forecast Portfolio Adjustment Per MWh =

(sum of the Prompt Quarter Final Forecast Portfolio Adjustment for each hour in the Supply Quarter)

(Forecasted Customer Metered Load for each Supply Quarter) x (1 � FL%)



�Prompt Quarter Final Forecast Portfolio Adjustment� means the amount calculated as follows:

[Prompt Quarter Final Forecast Customer Load-(Volume of Hedging Agreements acquired + final Target Portfolio)] x forecasted Pool Price for that hour (as determined in Section 6.1.2 of the Terms of Settlement).

6. Settlement Costs

The �Settlement Costs� will be determined as follows:

Settlement costs =

((Independent Advisor estimated costs for the Supply Quarter + Consultation Parties� estimated costs for the Supply Quarter + Third Party Advisor estimated costs for the Supply Quarter) + [(Consultation Parties� estimated negotiation costs + Independent Advisor estimated negotiation costs + Third Party Advisor estimated negotiation costs + EEC external negotiation costs + estimated 2004 Settlement Cost) / 6 ]

Forecasted Customer Metered Load for each Supply Quarter

7. Energy Risk Compensation

EEC is entitled to $�/MWh on Metered Load, net of the percentage of the Full Load filled through the FL�RFPs (�Energy Risk Compensation�).

8. Administration Charge

For staffing and administering the Terms of Settlement and EPSP, EEC is entitled to $0.50 for each MWh of Metered Load. 9. Quarterly Rates

EEC will use estimates of Monthly costs and expenses in order to determine the Filed Rates, which will be expressed in $/kWh. The Monthly electric energy price will be aggregated into Quarterly rates as defined by the following: Quarterly Rate 1 = Q1 2005 Quarterly Rate 2 = Q2 2005 Quarterly Rate 3 = Q3 2005 Quarterly Rate 4 = Q4 2005 Quarterly Rate 5 = Q1 2006 Quarterly Rate 6 = Q2 2006



The following formula will be used to determine the �Quarterly Rate�:

Quarterly Rate 1 = ([(MEP Jan)(FL Jan) + (FMEP Feb)(FL Feb) + (FMEP Mar)(FL Mar) + ∆ Settlement Period for 2004]/ Forecasted Customer Metered Load for Q1 2005) + Settlement costs + ∆ Settlement Costs + (Pool Trading Charges /(1-UFE&L)) + Administration Charges

Quarterly Rate 2 = ([(MEP Apr)(FL Apr) + (FMEP May)(FL May) + (FMEP June)(FL Jun) + ∆ Settlement Period for 2004 + ∆ Settlement Period Q1 2005]/ Forecasted Customer Metered Load for Q2 2005) + Settlement costs + ∆ Settlement Costs + (Pool Trading Charges /(1-UFE&L)) + Administration Charges + 2004 Final Settlement Adjustment

Quarterly Rate 3 = ([(FMEP Jul)(FL Jul) + (FMEP Aug)(FL Aug) + (FMEP Sep)(FL Sep) + ∆ Settlement Period Q2 2005] / Forecasted Customer Metered Load for Q3 2005) + Settlement costs + ∆ Settlement Costs + (Pool Trading Charges/(1-UFE&L)) + Administration Charges

Quarterly Rate 4 = ([(FMEP Oct)(FL Oct) + (FMEP Nov)(FL Nov) + (FMEP Dec)(FL Dec) + ∆ Settlement Period Q3 2005] / Forecasted Customer Metered Load for Q4 2005) + Settlement costs + ∆ Settlement Costs + (Pool Trading Charges/(1-UFE&L)) + Administration Charges

Quarterly Rate 5 = ([(MEP Jan)(FL Jan) + (FMEP Feb)(FL Feb) + (FMEP Mar)(FL Mar)+ ∆ Settlement Period Q4 2005] / Forecasted Customer Metered Load for Q1 2006) + Settlement costs + ∆ Settlement Costs + (Pool Trading Charges/(1-UFE&L)) + Administration Charges

Quarterly Rate 6 = ([(MEP Apr)(FL Apr)+(FMEP May)(FL May) + (FMEP Jun)(FL Jun) + ∆ Settlement Period Q1 2006] / Forecasted Customer Metered Load for Q2 2006) + Settlement costs + ∆ Settlement Costs + (Pool Trading Charges/(1-UFE&L)) + Administration Charges

where:

�MEP� = Monthly Energy Price for the Prompt Month of the applicable Quarter as determined by Sections 1 through 8 of this Energy Rate Calculation.

�FMEP� = forecast Monthly Energy Price for the Months of the applicable Quarter.

�FL� = Forecasted Customer Metered Load for each month of the applicable Quarter ten (10) Business Days prior to the applicable Filing Date.



�2004 Final Settlement Adjustment� = (the sum of the hourly difference between the initial load settlement and final settlement ) X the hourly price for the months of January, February, March, April and May 2004, as filed with the AEUB.

�∆ Settlement Costs� will be determined as follows:

�∆ Settlement Costs� =[(the variance between the estimated Settlement Costs and the Actual Settlement Cost), divided by Forecasted Customer Metered Load for each Supply Quarter

�Actual Settlement Costs� are AEUB approved costs

�m� = months

�Power Pool Trading Charges� = The prevailing rate ($/MWh) set by the AESO

�∆ Settlement Period� will be determined as follows:

∆ Settlement Period =

m Σ

I=0

[(the variance between (FMEPi x FLi) and (MEPi x Forecasted Customer Metered Loadi) as determined in accordance with Sections 1 through 10

of this Energy Rate Calculation, inclusive)]

+

m Σ i=0

[Alternative Hedge Settlement]

where:

�m� means the number of Months in 2004, 2005 and 2006 for which updated load and price settlement data are available.

�Alternative Hedge Settlement� means (i) once available, settlement amounts in respect of any Alternative Hedges held by the Consultation Parties against the Pool Price for those hours; and (ii) the adjustments set out in Sections 9.4 and 9.5 of the Procurement Protocol.

The adjustments for ∆ Settlement Periods 3 and 4 for 2004 EPSP will be included in the Energy Charge for the first and second quarters of 2005 under the Terms of Settlement.



Parties agree to include rate adjustments resulting from this agreement in the Energy Charge for the last two quarters of 2006 and first two quarters of 2007 in the Energy Charge. The rate adjustments include Settlement Costs for Q6, ∆ Settlement Period 6, and Energy Risk Compensation for Q6.

10. RCC Customer and NRCC Customer Rate Determination

Rates for RCC Customers and NRCC Customers will be adjusted in respect of forecasted RCC Customer hourly Load and forecasted NRCC Customer hourly Load (provided that the Consultation Parties have agreed to adjust the rates in respect of forecasted RCC Customer hourly Load and forecasted NRCC Customer hourly Load and given written notice thereof to EEC on or before November 30, 2004, and provided that the proposed adjustment has no adverse financial impact on EEC or EEMI).





CERTIFICATION OF COMPLIANCE PROCUREMENT ROUND

1. RFP Certification of Compliance

THIS CERTIFICATION OF COMPLIANCE is made in respect of the RFP held [Insert Date] for the acquisition of [Insert Full Load or Block Load] supplies for [Insert Period, Year]. The RFP acquisition of supply for 2005, Q1 2006 and Q2 2006 is under the Energy Price Setting Plan dated October 15, 2004 (�Energy Price Setting Plan�).

RFP Summary Table A-1 below summarizes the outcome of the RFP. Capitalized terms used in this Certification of Compliance, and not otherwise defined herein, have the respective meanings ascribed to those terms in Appendix 1 to the Energy Price Setting Plan. The table is meant as a guideline and may be adjusted as appropriate if agreed to by the parties.

A general description of the implementation of the various steps of the Procurement Protocol applicable to the RFP is to be set out in Appendix 2.

COMMENTS

General Comments

Comments of the Independent Advisor

Comments of the Consultation Parties�

Comments of EEC and the Designated Trader

This Certification of Compliance may be executed by facsimile transmission and acknowledged in multiple counterparts and by different parties in separate counterparts, each of which shall be an original and all of which shall be and constitute one and the same instrument.

EUB Decision 2004-0xx (October 26, 2004) � 14


SUBJECT TO THE COMMENTS, THE UNDERSIGNED HEREBY CERTIFY THAT RFP held [insert dates], was implemented, and the Products summarized in Table A-1 above, were acquired or sold in compliance with the Energy Price Setting Plan.

DATED as of the [Insert Date] day of [Insert Month], [Insert Year].

[Insert Name] [Insert Name] Independent Advisor Consultation Party representative

[Insert Name] [Insert Name] EEC representative Consultation Party representative



TABLE A-1

RFP HELD [Insert Date]

Total Volume

Threshold Price

Minimum Volume

Original Target Volume

Original Discretionary Volume

Ceiling Price

Final Target Volume

Final Discretionary Volume

TWAP

# Of Counterparties with Conforming Offers

Minimum Volume Acquired

Minimum Volume Weighted Average Price

Target Volume Acquired

Actual Target Volume Weighted Average Price

Discretionary Volume Acquired

Discretionary Volume Average Price

# Of Counterparties Selected



2. Quarterly Procurement Certification of Compliance

THIS CERTIFICATION OF COMPLIANCE is made in respect of the [Insert Round #] Procurement Round of acquisition of Target Volume supplies for [Insert Period, Year] which was held [Insert dates]. The Round acquisition of supply for 2005, Q1 2006 and Q2 2006 is under the Energy Price Setting Plan dated October 15, 2004 (�Energy Price Setting Plan�).

Description of Implementation of Protocol The phases and steps to be summarized are with respect to the Procurement Protocol set out in Appendix 2 to the Energy Price Setting Plan. Capitalized terms used in this Certification of Compliance, and not otherwise defined herein, have the respective meanings ascribed to those terms in Appendix 1 to the Energy Price Setting Plan.

A general description of the implementation of the various steps of the Procurement Protocol applicable to the Procurement Round is to be set out under the heading �Description of Implementation�. All steps of a phase are not necessarily applicable to the Round.

(A) DETERMINE TARGET VOLUME AND TARGET PRICE FOR PRODUCTS

Summary of Steps Description of Implementation Step 1(i): Determine daily Target Volumes for each product to be acquired or sold as set by the Independent Advisor.

See Table A-1

Step 1(ii): Record the Target Prices as set by Independent Advisor.

See Table A-1

Step 1(iii): Communicate to the Designated Trader the Target Volumes and Target Price for each Product throughout day.



Table A-1: Daily Round Target Volume (MW) and Target Prices ($/MWh) Communicated to the Designated Trader

Date Time Product Period Product MW Price ($/MW)

(B) ACQUISITION OR SALE OF TARGET VOLUME

Summary of Steps Description of Implementation

Step 1(i): Designated Trader will complete - price and volume details of any Hedging Agreements acquired or sold.

See Table B-1

Step 1(ii): Determine remaining Target Volumes for each Product to be acquired this Round.

See Table B-2

Table B-1: TRADING � Load and Acquisition Price Details of Hedging Agreements Acquired or Sold

Date Time Product Period Product Price

($/MW) Counter-Party

Table B-2: Remaining Target Volumes for Each Product this Round (MWh)

Period Product Target Volumes

Remaining Current Round

Acquisitions Un-Acquired

Target Volumes



(C) DETERMINATION OF ENERGY PORTFOLIO PRICES PHASE

Summary of Steps Description of Implementation Step 1(i): Calculate the weighted average price of each Product acquired.

See Table C-1

Step (ii): Apply all applicable trading costs to prices.

See Table C-1

Table C-1: Products Acquired in Procurement Round

Date Product Volume (MW)

Independent Advisor

Target Price (A-1)

($/MWh)

Transaction Price (B-1) ($/MWh)

Transfer Price (including incentive sharing)

(($/MWh) Comments

(D) COMMENTS

General Comments Comments of the Independent Advisor

Comments of the Consultation Parties�

Comments of EEC and the Designated Trader

This Certification of Compliance may be executed by facsimile transmission and acknowledged in multiple counterparts and by different parties in separate counterparts, each of which shall be an original and all of which shall be and constitute one and the same instrument.



SUBJECT TO THE COMMENTS, THE UNDERSIGNED HEREBY CERTIFY THAT the [Round #] Procurement Round, held [insert dates], was implemented, and the Products summarized in Table C-1 above, were acquired or sold in compliance with the Energy Price Setting Plan.

DATED as of the [Insert Date] day of [Insert Month], [Insert Year].

[Insert Name] [Insert Name] EEC representative Consultation Party representative

[Insert Name] [Insert Name] Independent Advisor Consultation Party representative





2001 TO 2004 HISTORIC HOURLY POOL PRICE INDICES





CODE OF CONDUCT

1. Capitalized terms used in this Appendix 6 that are not otherwise defined herein, have the respective meanings ascribed to those terms in Schedule �A� of the Terms of Settlement or Schedule �A� of Appendix 2 of the EPSP.

2. EEC, the representatives of the Consultation Parties, the Independent Advisor, the Third Party Advisor, the Board Observer and EEMI are each privy to certain commercially sensitive information in connection with the Energy Price Setting Plan and the Terms of Settlement (the �Commercially Sensitive Information�). The Commercially Sensitive Information is comprised of the following information:

(a) the Quarterly Product Schedules for 2005�2006 (other than in respect of the Supply Quarter);

(b) the Target Portfolio;

(c) forecasts of prices and volumes;

(d) Intersession Target Volumes and Target Prices;

(e) details of and individual components regarding the calculation of the Energy Rate Calculation;

(f) specific counterparty information associated with individual offer prices in the RFPs ;

(g) Volume and price of EEMI RFP Offers;

(h) the Daily Summary Report;

(i) the Procurement Protocol; and

(j) all information provided in accordance with Appendices 1 and 2 of the EPSP.

3. The Independent Advisor, the Third Party Advisor, the Board Observer and all personnel and professional advisors retained by EEC, the representatives of the Consultation Parties and EEMI, who will be privy to certain Commercially Sensitive Information, (the �Confidential Parties�) will be required to sign a Confidentiality Agreement. The form of the Confidentiality Agreement is attached as Exhibit 6-1 to this Code of Conduct.

4. EEC, the representatives of the Consultation Parties and EEMI will only permit access to the Commercially Sensitive Information to those personnel and professional



advisors who need to have access to that Commercially Sensitive Information for the purpose of implementing the Energy Price Setting Plan and the Terms of Settlement.

5. In order to implement the Energy Price Setting Plan and the Terms of Settlement, the Confidential Parties will need to disclose or reveal the Commercially Sensitive Information amongst themselves in various circumstances. Exhibit 7-2 attached to this Code of Conduct sets out the categories of Commercially Sensitive Information described in paragraph 2 above, indicates to what Commercially Sensitive Information each of the Confidential Parties are entitled to be privy, and to whom that Commercially Sensitive Information may be disclosed or revealed (provided that person has signed a Confidentiality Agreement in the form attached as Exhibit 6-1).

6. The Confidential Parties will:

(a) keep the Commercially Sensitive Information strictly confidential;

(b) not use the Commercially Sensitive Information for any purpose other than implementing the Energy Price Setting Plan and the Terms of Settlement; and

(c) not disclose or reveal the Commercially Sensitive Information to any person or entity, except as set out in this Code of Conduct and Exhibit 6-2.

7. If EEC, the representatives of the Consultation Parties, the Independent Advisor, the Board Observer or EEMI become aware of an unauthorized disclosure or unauthorized use, or a possible unauthorized disclosure or unauthorized use, of Commercially Sensitive Information (the �Possible Unauthorized Use or Disclosure�) that party will immediately report the concern to each of the other parties.

8. In the event a Possible Unauthorized Use or Disclosure is reported, EEC, the Consultation Parties, the Independent Advisor, the Board Observer and EEMI will meet within forty eight (48) hours of the report being circulated to discuss the concerns contained in that report.



Exhibit 6-1 to the Code of Conduct

CONFIDENTIALITY AGREEMENT

TO: [EEC/Consultation Parties/EEMI (as may be applicable)]

WHEREAS:

(a) ENMAX Energy Corporation (�EEC�) has adopted the electric energy price setting method set out in its Energy Price Setting Plan dated October 15, 2004 (the �EPSP�) and the Terms of Settlement dated October 15, 2004 (the �Terms of Settlement�), for the purposes of acquiring an electric energy supply and setting the electric energy price for eligible customers who receive service under EEC�s regulated rate tariff transition (�RRT�) rate in the ENMAX Power Corporation service area (the �RRT Transition Rate Load�). Implementation of the EPSP and the Terms of Settlement will involve rounds of over-the-counter and exchange based procurement to acquire an electric energy supply for the RRT Transition Rate Load.

(b) The EPSP, as may be amended and adjusted from time to time, contains commercially sensitive information (�Commercially Sensitive Information�), including specific pricing parameters and energy procurement strategies, developed for the purpose of electric energy price setting for EEC�s RRT transition rate. The disclosure of the Commercially Sensitive Information could adversely affect EEC�s ability to acquire electric energy supplies for the eligible customers and/or the costs incurred by EEC to acquire those supplies.

(c) Appendix 6 to the EPSP contains a Code of Conduct (the �Code of Conduct�) in which EEC and the Consultation Parties have provided for the use and disclosure of the Commercially Sensitive Information, in respect of the EPSP and the Terms of Settlement.

NOW THEREFORE, in consideration of the foregoing and the agreements contained herein (the receipt and adequacy of which are acknowledged), the undersigned agrees, acknowledges and confirms as follows:

1. The undersigned has read and understands the Code of Conduct and agrees to abide by these provisions and the spirit and intent of the Code of Conduct. Subject to Section 2 below, until April 1, 2009 the undersigned agrees:

(a) to keep the Commercially Sensitive Information strictly confidential;

(b) not to use the Commercially Sensitive Information for any purpose other than implementing the EPSP and the Terms of Settlement; and



(c) not to disclose or to reveal the Commercially Sensitive Information to any person or entity, except as expressly permitted in the Code of Conduct.

2. The provisions of this Confidentiality Agreement relating to Commercially Sensitive Information will not apply to any part of such Commercially Sensitive Information that is now or subsequently becomes part of the public domain through no violation of the Confidentiality Agreement or as may be required to be disclosed by law or the order of a court or regulatory authority.

3. If the undersigned becomes aware of a breach, or of any information the undersigned believes may indicate a breach, by any other person who is a party to an agreement corresponding to this Confidentiality Agreement, the undersigned will immediately report that breach or possible breach to the Independent Advisor and conduct himself or herself in accordance with the reasonable and lawful directions of the Independent Advisor.

4. The undersigned acknowledges that mishandling or unauthorized use or disclosure by the undersigned of Commercially Sensitive Information could cause irreparable harm and significant injury to EEC, EEC's RRT customers and/or EEC�s affiliates.

5. The undersigned understands that a breach of this Confidentiality Agreement could result in disciplinary action, if intentional, including possible termination of his or her employment.

AGREED TO this _____ day of , 2004.

_______________________________

_______________________________ Print Name and Title



Exhibit 6-2 to the Code of Conduct

Capitalized terms used in this Exhibit 6-2 have the respective meanings ascribed to those terms in Schedule �A� of Appendix 2 to the Energy Price Setting Plan and the Code of Conduct. For greater certainty, an �X� denotes a party who will be privy to that particular Commercially Sensitive Information and the other party(ies) to whom Commercially Sensitive Information may be disclosed or revealed (provided that person has signed a Confidentiality Agreement in the form attached to the Code of Conduct as Exhibit 6-1).

Commercially Sensitive

Information

EEC Representatives of Consultation

Parties

EEMI Trading

Personnel

EEMI Portfolio

Management Personnel

Independent Advisor

Third Party

Advisor

Board Observer

a) Quarterly Product Schedules for 2005�2006 (other than in respect of the Supply Quarter)

X X X X

X

b) Target Portfolio X X X X X

c) Forecasts of prices and volumes

X X X X X

d) Intersession target volumes and target price

X X X X X

X

e) Details of and individual components regarding the calculation of the Energy Rate Calculation

X X X X

X

f) Specific counterparty information associated with individual offer price in the RFPs

X* X

g) Volume and price of EEMI RFP Offers

X* X** X*** X

h) Daily Summary Report X X X X X

X



i) Procurement Protocol X X X X X X

* Only those persons referred to in Section 3.3.2 of Appendix 2 of the EPSP will have access to this information.

** Only the representative of the Consultation Parties referred to in Section 3.3.3 of Appendix 2 of the EPSP will have access to this information, in accordance with the conditions set out in that Section.

*** EEMI Portfolio Management Personnel are only to have access to information related to completed transactions and then only after transactions have been completed.





DETERMINATION OF FORECAST MONTHLY PRICE AND FORECAST ELIGIBLE CUSTOMER LOAD

Capitalized terms used in this Appendix 7, and not otherwise defined herein, have the meanings set out in Schedule �A� of the Terms of Settlement. This Appendix 7 may be amended subject to agreement of the Consultation Parties and EEC.

1. Determination of Forecast Monthly Price

EEC will determine the Forecast Monthly Price for the Prompt Quarter and for each of the remaining Quarters to and including Q2 2006. This determination by EEC will result in a set of forward prices for those Months for Baseload Products and On-peak Products.

The price for Baseload Products will be determined over the five (5) Business Days immediately preceding the Business Day that the Prompt Quarter forecasts are to be provided to the Consultation Parties under Section 5.1 of the Terms of Settlement (the �Determination Period�), and will be based on the arithmetic average of the following:

a. arithmetic average of all trades (equal to or greater than ten (10) MW) for Baseload Product on each Exchange for the Determination Period; provided that if no trades (equal to or greater than ten (10) MW) for Baseload Product take place on an Exchange for any Business Day in the Determination Period, the settlement price for Baseload Product on that Exchange will be the price for that Business Day;

b. the arithmetic average of all trades (equal to or greater than ten (10) MW) for Baseload Product for the Determination Period as reported by Natsource or any other price reporter (as may be agreed to by EEC and the Representatives); provided that:

i. if no trades (equal to or greater than ten (10) MW) for Baseload Product are reported for Natsource or any other over-the-counter electric energy broker (as may be agreed to by EEC and the Representatives), the mid-market of the bid/offer spread (provided that the bid/off spread is less than or equal to $1.50 per MWh) as reported by Natsource or any other over-the-counter electric energy broker (as may be agreed to by EEC and the Representatives) will be the price for that Business Day; and

ii. if no trades or bid/offer spreads as set out in paragraph b.i. above are available for any Business Day in the Determination Period, no price for that Business Day will be used for the purpose of this paragraph b; and

c. the arithmetic average of the �Mid-Market Price� for Baseload Product for the Determination Period as reported by the Daily Chase Energy Canada Fundamentals Report.




In connection with Table 2a of Appendix 1 to the Energy Price Setting Plan, the price for On-peak Products for each applicable Month will be determined by: the ratio of the peak (6x16) historic hourly Pool Prices to the Baseload historic hourly Pool Prices for that Month, utilizing the three (3) year historic hourly Pool Prices set out in Appendix 5 to the Energy Price Setting Plan, multiplied by the price for Baseload Products for that Month (as determined above).

For greater certainty, the phrase �forecasted Pool Price for that hour� contained in the formula set out in Section 7.2 of the Terms of Settlement will be determined by EEC and based on an hourly forecast Pool Price. The hourly forecast Pool Price will be determined by the Prompt Quarter price for Baseload Product and the three (3) year historic hourly Pool Prices set out in Appendix 6 to the Energy Price Setting Plan.

2. Determination of Forecast Eligible Customer Load

EEC will determine the Forecast Eligible Customer Load for the Prompt Quarter and for each of the remaining Quarters to and including Q2 2006.

For each hour of the Prompt Quarter and for each of the remaining Quarters to and including Q2 2006, EEC will determine the Forecast Eligible Customer Load in respect of RCC Customers and NRCC Customers by reference to the following (the �Parameters�):

(a) net forecasted growth/attrition rate (as a percentage) for RCC Customers and NRCC Customers;

(b) normalized daily temperatures for the Month;

(c) historical hourly Load for RCC Customers and NRCC Customers; and

(d) historical Unaccounted for Energy and Losses for RCC Customers and NRCC Customers.

Estimated site counts for RCC Customers and NRCC Customers will be provided to the Representatives and may be used as a variable in determining the Forecast Eligible Customer Load.

Estimated shape of the Load for RCC Customers and NRCC Customers will be provided to the Representatives and may be used as a variable in determining the Forecast Eligible Customer Load.

The Prompt Quarter Final Forecast Customer Load will set out the final values in respect of the Parameters and the corresponding changes in values in respect of the Parameters (together with written explanations for those Parameters and, on a best efforts basis, written explanations in respect of changes in site counts and Load Shape), as compared to the immediately preceding Forecast Eligible Customer Load for that Prompt Quarter. For each of the remaining Quarters to and including Q2 2006, the Forecast Eligible Customer Load will include any changes in values in respect of the Parameters as compared to the immediately preceding Forecast Eligible Customer Load for that Quarter.

PUBLIC NOTICE

REGULATED RATE TARIFFCity of Calgary, Residential and Small Commercial Customers

Take notice that ENMAX Energy Corporation ("EEC")intends to commence negotiations with interestedparties in the ENMAX Power Corporation servicearea (City of Calgary) with respect to its RegulatedRate Tariff for residential and small commercial customers for the period from January 2005 to theend of June 2006. EEC believes the main issues tobe negotiated will include the energy price settingmethodology and the return margin on customers bills to be paid to EEC.

The negotiations will be conducted in accordancewith the Alberta Energy and Utilities BoardNegotiated Settlement Guidelines.

Any party wishing to participate in the negotiationsas an intervener must file a Request to Participatewith the Board. The Request to Participate shallinclude a detailed statement describing the nature ofthe party’s interest in the proceeding and the natureof the party’s intended participation. Please file theRequest to Participate with the Board on or beforeJuly 12, 2004. Refer to Application #1348671.

To obtain additional information, please contact:

Shelley Radway, Regulatory SpecialistENMAX Corporation 141 - 50th Avenue S.E.Calgary, Alberta T2G 4S7Telephone: (403) 514-2742Facsimile: (403) 514-3061E-mail: [email protected]

Authority to Enter into a Negotiated Settlement Process

In accordance with the revised Negotiated Settlement Guidelines (IL 98-04), thePublic Institutional Consumers of Alberta (PICA) hereby provide the following authorization:

PICA hereby gives authority to Raj Retnanandan and Nancy McKenzie to negotiate with ENMAX on behalf of PICA and to participate in negotiations to set ENMAX’s 2005 and 2006 Regulated Rate Tariff (“RRT”) Procurement framework and Hedge Portfolio for 2005 and 2006 as representative of the public institutional sector.

This authority includes the authority to settle issues and enter into a Settlement Agreement.

Dated the 28th day of September, 2004

Signed:

E. Michael Higgins PICA Executive

Documents

Decision 2004-098: ENMAX - 2005-2006 Regulated Rate Tariff ...€¦ · 2005-2006 Regulated Rate Tariff Part C: Energy Price Setting Plan Negotiated Settlement October 26, 2004. ALBERTA