Alberta Electric System Operator - AUC Home · 2018-02-23 · Decision 2013-025 Alberta Electric System Operator Objections to ISO rules Section 203.6 Available Transfer Capability

Decision 2013-025

Alberta Electric System Operator Objections to ISO rules Section 203.6 Available Transfer Capability and Transfer Path Management February 1, 2013

The Alberta Utilities Commission Decision 2013-025: Alberta Electric System Operator Objections to ISO rules Section 203.6 Available Transfer Capability and Transfer Path Management Application Nos. 1607958, 1607986, 1607987, 1607988, 1607993 and 1608013 Proceeding ID No. 1633 Published by The Alberta Utilities Commission Fifth Avenue Place, Fourth Floor, 425 First Street S.W. Calgary, Alberta T2P 3L8 Telephone: 403-592-8845 Fax: 403-592-4406 Web site: www.auc.ab.ca

AUC Decision 2013-025 (February 1, 2013) • i

Contents

1 INTRODUCTION ................................................................................................................. 1 1.1 The application ............................................................................................................... 1 1.2 The objections ................................................................................................................ 2 1.3 Process schedule............................................................................................................. 3

2 BACKGROUND ON INTERTIES AND AVAILABLE TRANSFER CAPABILITY .. 4 2.1 Introduction to interties .................................................................................................. 5 2.2 The AB-BC intertie ........................................................................................................ 6 2.3 The AB-SK Intertie ........................................................................................................ 6 2.4 The MATL intertie ......................................................................................................... 7 2.5 Current ATC rule and the development of the Proposed ATC Rule ............................. 7

3 REGULATORY FRAMEWORK ....................................................................................... 8 3.1 Statutory interpretation................................................................................................... 8 3.2 Legislation ...................................................................................................................... 9

4 INTERTIES, AVAILABLE TRANSFER CAPABILITY AND ACCESS TO THE ALBERTA INTERCONNECTED ELECTRONIC SYSTEM ............................................... 11

4.1 Are interties part of the transmission system and the Alberta interconnected electric system? ......................................................................................................................... 11

4.2 What is the nature of ATC and how is it created? ....................................................... 12 4.3 How can ATC be allocated? ........................................................................................ 15 4.4 What is the AESO’s obligation to provide access to the AIES? .................................. 16

4.4.1 Access to the AIES ......................................................................................... 16 4.4.2 Access for anticipated versus scheduled energy ............................................. 20

5 GROUNDS FOR OBJECTIONS ...................................................................................... 23 5.1 Rule does not support the FEOC operation of the market ........................................... 23

5.1.1 Economic incentives ....................................................................................... 24 5.1.2 Open competition considerations .................................................................... 28 5.1.3 Rule fails to alight with existing AESO practices .......................................... 29 5.1.4 Rule fails to align with existing North American practices ............................ 32 5.1.5 Rule negatively impacts pool price ................................................................. 34 5.1.6 Rule leads to increased bookout fees .............................................................. 37 5.1.7 Rule impacts parties with firm transmission rights in other jurisdictions ...... 39 5.1.8 Rule was not finalized when an investment decision was made .................... 41 5.1.9 Summary of Commission findings - FEOC .................................................... 41

5.2 Rule is not in the public interest ................................................................................... 41 5.2.1 Transmission Regulation Section 16 and allocation of availability transfer

capability ......................................................................................................... 41 5.2.2 Transmission Regulation Section 27 and cost responsibilities of merchant

interties ............................................................................................................ 44 5.2.3 Previous commitments for connection of MATL ........................................... 48 5.2.4 Seams issue between jurisdictions .................................................................. 50 5.2.5 Summary of Commission findings – public interest ....................................... 51

5.3 Rule is technically deficient ......................................................................................... 51 5.3.1 Rule prematurely incorporates a pricing mechanism ...................................... 52 5.3.2 Rule fails to adequately address allocation and curtailment of ancillary

services ............................................................................................................ 53

ii • AUC Decision 2010-025 (February 1, 2013)

5.3.3 Rule fails to account for existing transmission commitments ........................ 54 5.3.4 Rule incorrectly allocates ATC created by LSSi ............................................ 55 5.3.5 Rule is insufficiently transparent and is missing definitions .......................... 56 5.3.6 Rule uses incorrect values for the calculation of pro-rata allocation .............. 58 5.3.7 Rule fails to reallocate stranded capacity between T-85 and T-20 ................. 60 5.3.8 Rule fails to contemplate future interties ........................................................ 60 5.3.9 Summary of Commission findings – technically deficient ............................. 61

6 RELIEF REQUEST AND ORDER .................................................................................. 62

Appendix 1 – Proceeding participants ...................................................................................... 63

Appendix 2 – Abbreviations ....................................................................................................... 65

Appendix 3 – Propsed ISO rules Section 203.6: Available Transfer Capabilty and Transfer Path Management ............................................................................................... 67

List of tables Table 1. ISO Rules filed December 5, 2011 with the Commission ........................................ 1

List of figures Figure 1. NERC interconnections. ............................................................................................. 4

Figure 2. Interconnections between Alberta and neighbouring jurisdictions. ...................... 5

AUC Decision 2013-025 (February 1, 2013) • 1

The Alberta Utilities Commission Calgary, Alberta Alberta Electric System Operator Decision 2013-025 Objections to ISO rules Section 203.6 Application Nos. 1607958, 1607986 Available Transfer Capability 1607987, 1607988, 1607993 and 1608013 and Transfer Path Management Proceeding ID No. 1633

1. The Alberta Electric System Operator (AESO) has proposed a rule to allocate transmission capacity between interties that connect Alberta to adjacent jurisdictions. After considering evidence and arguments presented by market participant objectors (MPOs) and their supporters, for reasons given below in this decision the Alberta Utilities Commission (AUC or the Commission) has not been persuaded that the rule is against the public interest or the fair, efficient and openly competitive operation of the electricity market in Alberta or that the rule is technically deficient.

1 Introduction

1.1 The application

2. On December 5, 2011, the AESO filed Independent System Operator (ISO) rules Section 203.6: Available Transfer Capability and Transfer Path Management (Proposed ATC Rule) with the AUC in accordance with Section 20.2(1) of the Electric Utilities Act, S.A. 2003, c. E-5.1. The filing was assigned Application No. 1607958.

3. The AESO’s December 5, 2011 notice of filing advised that with the pending energization of the Montana Alberta Tie Limited (MATL) intertie in 2012, the AESO must proceed to allocate system available transfer capability (ATC) in a different fashion to ensure transaction volumes remain within limits

4. The AESO stated that the Proposed ATC Rule reflects a consolidation and rationalization of the existing operating policies and procedures (OPPs) indicated in Table 1 below.1 A copy of the proposed rule is available in Appendix 3.2

Table 1. ISO Rules filed December 5, 2011 with the Commission

1 Exhibit 0027.00, ISO Notice of Filing, December 5, 2011, page 2. 2 Exhibit 0018.00, New ISO Rules Section 203.6, December, 5, 2011.

Rule Rule name and description Proposed action

Section 203.6 Available Transfer Capability and Transfer Path Management New OPP 301

Alberta-BC Interconnection Scheduling

Remove OPP 302

Alberta-Saskatchewan Interconnection Scheduling

Remove OPP 303

Alberta-BC Interconnection Operation

Remove OPP 304

Alberta-BC Interconnection Transfer Limits

Remove OPP 306

Reliability Curtailments to Alberta-Saskatchewan Transactions

Remove OPP 307

Alberta-Saskatchewan Interconnection Transfer Limits

Remove

OPP 309 Saskatchewan Inadvertent Energy Management Remove

ISO rule 6.3.3 Interconnection Dispatching Remove

Objections to ISO rules Section 203.6 Available Transfer Capability and Transfer Path Management Alberta Electric Systems Operator

2 • AUC Decision 2013-025 (February 1, 2013)

5. As required by Section 20 of the Electric Utilities Act, the Commission issued a notice of filing and notice for objection in respect of the ISO rules listed above on December 9, 2011.3

1.2 The objections

6. Section 20.4(1) of the Electric Utilities Act permits a market participant to object to an ISO rule on one or more of the following grounds:

(a) that the ISO, in making the ISO rule, did not comply with Commission rules under section 20.9;

(b) that the ISO rule is technically deficient;

(c) that the ISO rule does not support the fair, efficient and openly competitive operation of the market;

(d) that the ISO rule is not in the public interest.

7. Notices of objections regarding the Proposed ATC Rule were received by the December 19, 2011 deadline from the following market participants and assigned the following application numbers:

ATCO Power Ltd. (ATCO Power) – Application No. 1607988 British Columbia Hydro and Power Authority (BC Hydro) – Application No. 1607993 Cargill Limited (Cargill) – Application No. 1607990 NorthPoint Energy Solutions Inc. (NorthPoint) - Application No. 1608013 PowerEx Corporation (PowerEx) - Application No. 1607987 Saskatchewan Power Corporation (SaskPower) - Application No. 1607986 TransCanada Energy Ltd. (TransCanada) – Application No. 1607989.

8. Cargill and TransCanada were originally treated as MPOs. However, both parties subsequently clarified they were not objecting to the Proposed ATC Rule but were rather supporting the MPOs, and as such the Commission closed Application Nos. 1607990 and 1607989.4

9. PowerEx indicated that it would form a coalition with NorthPoint and Cargill for preparing joint submissions (the Coalition).5

10. Based on one or more of the following grounds MPOs submitted that the Proposed ATC Rule is technically deficient, does not support the fair, efficient and openly competitive operation of the market and is not in the public interest, being the grounds for objection identified in Section 20.4(1)(b), (c) and (d) of the Electric Utilities Act. None of the MPOs objected on the basis of Section 20.4(1)(a) of the Electric Utilities Act.

11. The Commission combined the aforementioned applications into Proceeding ID No. 1633 to address the objections to the Proposed ATC Rule, and on December 23, 2011, the

3 Exhibit 0048.00, AUC Notice of Filing, December 9, 2011. 4 Exhibit 0077.01, AUC Letter re Cargill status, February 16, 2012, and Exhibit 0068.01, AUC Letter re

TransCanada status, February 7, 2012. 5 Exhibit 0094.01, PowerEx Procedural Submission, March 21, 2012, page 2.



Commission issued a notice of proceeding and requested statements of intent to participate from interested parties.6

1.3 Process schedule

12. Statements of intent to participate were received from the following parties:

AESO Capital Power Corporation (Capital Power) ENMAX Energy Corporation (ENMAX) Montana Alberta Tie Ltd. c/o Enbridge Inc. (Enbridge/MATL) Morgan Stanley Capital Group Inc. (Morgan Stanley) NaturEner USA, LLC (NaturEner) Saskatchewan-Alberta Tie Line Project (SATL) Utilities Consumer Advocate (UCA) Consumers Coalition of Alberta (CCA).

13. On February 17, 2012, the AUC issued a proceeding schedule that originally set the oral hearing to begin on April 30, 2012.7 In response to requests from parties to reschedule the hearing due to various conflicts, on March 30, 2012, the AUC issued a subsequent notice which set out an updated process schedule with an oral hearing planned to start September 10, 2012.8 The proceeding schedule was revised again on May 1, 2012 to adjust the deadlines for filing evidence, but the hearing remained scheduled for September 10, 2012.9

14. At the oral hearing the Commission gave directions that written argument was due from the MPOs and MPO supporters on October 15, 2012, and reply argument from the AESO and parties supporting the AESO was due October 29, 2012. Rebuttal argument from the MPOs, Cargill, TransCanada and the UCA only was due November 5, 2012.

15. The Commission considers the close of record for this proceeding was November 5, 2012, when the final reply argument was filed.

16. In reaching the determination contained within this Decision, the Commission has considered all relevant materials comprising the record of this proceeding, including the evidence and argument provided by each party. Accordingly, references in this decision to specific parts of the record are intended to assist the reader in understanding the Commission’s reasoning relating to a particular matter and should not be taken as an indication that the Commission did not consider all relevant portions of the record with respect to that matter.

6 Exhibit 0056.01, AUC Notice of Proceeding, December 23, 2011. 7 Exhibit 0078.01, AUC Proceeding Schedule, February 17, 2012. 8 Exhibit 0101.01, AUC Proceeding Schedule, March 30, 2012. Deadlines relating to arguments were provided

after the oral hearing in exhibit 0267.01, AUC Argument Schedule, September 25, 2012. 9 Exhibit 0126.01, AUC Proceeding Schedule, May 1, 2012.



2 Background on Interties and Available Transfer Capability

17. The following maps are provided for the convenience of the reader. Figure 1 indicates the North American Electric Reliability (NERC) regional entities, and Figure 2 indicates the interconnections between Alberta and neighbouring jurisdictions.

Figure 1. NERC interconnections. 10

10 Exhibit 0144.02, Morgan Stanley Evidence, June 15, 2012, page 8.



Figure 2. Interconnections between Alberta and neighbouring jurisdictions. 11

2.1 Introduction to interties

18. Interties are transmission lines for electric energy that connect neighbouring transmission systems and allow the transfer of electric energy between those jurisdictions. Interties, like any other transmission line, have a path rating which is the maximum capacity for electric energy that can be safely and reliably transferred. The path rating is generally determined by the physical characteristics of the line or lines, such as the type of material in the wiring, the line capacity, transformer capacity, and other factors.

19. One or both of the jurisdictions connected by an intertie may not be able to safely and reliably send or receive electric energy up to the path rating, so the maximum capacity for electric energy that can be safely and reliably transmitted on the intertie is often less than the path rating. The amount of electric energy that can be reliably transferred over an intertie is called the total transfer capability (TTC). The amount of electric energy transferred over an intertie is often further reduced by what is known as the transmission reliability margin, or TRM. The TRM is the amount of transfer capability necessary to ensure the reliably operation taking into account uncertainties in system conditions and the need for operating flexibility. The commercially available transfer capability of an intertie is called the available transfer capability, or ATC, and is simply the TTC minus the TRM.

20. Depending on the physical characteristics of interties and the transmission systems there may be a simultaneous transfer limit; that is, one or more interties may be subject to the same TTC limit, and thus the same ATC limit. If there is a simultaneous transfer limit between

11 Exhibit 0136.02, SaskPower Evidence, May 7, 2012, Appendix A, page 8.



interties there has to be some way of allocating the ATC between the interties that are subject to simultaneous transfer limits.

21. The energization of MATL will result in a situation where a simultaneous limit applies to the MATL and AB-BC interties.12 The AESO’s Proposed ATC Rule contains a methodology for allocating ATC between interties when there is a simultaneous limit and there is more demand for ATC than there is capacity, and it is this methodology that is one of the key issues in this proceeding.

2.2 The AB-BC intertie

22. Alberta and British Columbia are both members of the Western Electricity Coordinating Council (WECC) which is responsible for coordinating and promoting bulk electric system reliability in Alberta, British Columbia, all or portions of 14 western US states and the northern portion of Baja Mexico.13 WECC makes up the Western Interconnection as set out by the NERC. All of the electric utilities in the Western Interconnection are electrically tied together during normal system conditions and operate at a synchronized frequency.14 The AESO is a member of the WECC as per the WECC-AESO Membership and Operating Agreement.

23. BC Hydro described the AB-BC intertie as a 500-kV alternating current (AC) interconnection between the electric systems of Alberta and British Columbia. The AB-BC intertie consists of a 500-kV AC transmission line between Langdon, AB and Cranbrook, BC, a 138-kV AC transmission line between Pocaterra, AB and Natal, BC and a 138-kV AC transmission line between Coleman, AB and Natal, BC. The AB-BC intertie is designated by WECC as Path 1 and has a path rating of 1,200 MW for flows from British Columbia to Alberta and 1,000 MW for flows from Alberta to British Columbia. The WECC path ratings represent the maximum electric energy that can flow under realistic conditions while still meeting the appropriate reliability criteria. The AESO is the operator for the AB-BC intertie.15

2.3 The AB-SK Intertie

24. Saskatchewan is a member of the Midwest Reliability Organization (MRO), which is dedicated to ensuring the reliability and security of the bulk power systems in Saskatchewan, Manitoba, and all or portions of 9 Midwest US states. The MRO and several other reliability organizations in eastern Canada and the US form NERC’s Eastern Interconnection. All of the electric utilities in the Eastern Interconnection are electrically tied together during normal system conditions and operate at a synchronized frequency.16 The Eastern and Western Interconnections are tied to each other in a manner that permits a controlled flow of energy while also functionally isolating the independent AC frequencies of each interconnection.

12 Exhibit 0129.01, Coalition Evidence, May 7, 2012, page 7; Exhibit 0133.01, TransCanada Evidence, May 7,

2012, page 15; Exhibit 134.02, BC Hydro Evidence, May 7, 2012, pages 10-11; Exhibit 0145.02, AESO Evidence, June 15, 2012, page 7.

13 http://www.wecc.biz/About/Pages/default.aspx. 14 http://energy.gov/oe/recovery-act/recovery-act-interconnection-transmission-planning/learn-more-about-

interconnections. 15 Exhibit 0134.02, BC Hydro Evidence, May 7, 2012, page 2. 16 http://energy.gov/oe/recovery-act/recovery-act-interconnection-transmission-planning/learn-more-about-

interconnections.



25. SaskPower described the intertie connecting Alberta and Saskatchewan (AB-SK) as a single 230-kV transmission line that runs between Swift Current, SK to the McNeill converter station in Empress, AB. The McNeill converter station is a back-to-back direct current (DC) converter. Consequently the interface is not synchronous and is fully controllable. The converter station is connected to the Alberta interconnected electric system (AIES) via a single 138-kV AC transmission line to the Empress, AB substation. Power flow on the AB-SK intertie can be set at a specified amount and does not typically vary due to system conditions in real-time. However, the converter has a control system and an automatic power runback scheme that serves to keep the interconnection in service for a wide range of operating conditions. For example, should a major disturbance occur in either Saskatchewan or Alberta, the controls system can temporarily reduce the power flow, or automatically run back to the present value to preserve the AB-SK intertie. The AB-SK intertie has been designated by WECC as Path 2 and has a path rating of 150 MW for flows from Saskatchewan to Alberta, and also 150 MW path rating for flows from Alberta to Saskatchewan. ATCO Electric owns and operates the converter station, and the AESO provides system operating instructions to ATCO Electric.17

2.4 The MATL intertie

26. Montana, like Alberta, is a member of the WECC and thus the Western Interconnection. All of the electric utilities in the Western Interconnection are electrically tied together during normal system conditions and operate at a synchronized frequency.18

27. Enbridge/MATL described the intertie connecting Alberta and Montana as a 230-kV AC transmission line between Great Falls, MT and just outside Lethbridge, AB.19 Enbridge/MATL expects the AB-MT intertie to be energized sometime in the first quarter of 2013.20

2.5 Current ATC rule and the development of the Proposed ATC Rule

28. ISO rule Section 203.1: Offers and Bids for Energy, which is currently in effect, indicates in Section 3(3)(a) that all imports must be offered at $0/MWh, and in Section 7(2)(a) that all exports must be bid at $999.99/MWh. This means that all imports, regardless of the intertie, are priced identically at $0/MWh and all exports, regardless of the intertie, are priced identically at $999.99/MWh.

29. The AESO indicated that the current process for handling intertie transactions involves coordination with external electricity markets though an hourly process known as scheduling, which sets out by at least 15 minutes in advance of a delivery hour the flow or potential flow of energy between regions along the intertie. The AESO, as the operator of the AB-BC intertie,21 approves all pool participant import and export transaction schedule submissions (known as e-tags). If the submitted volume of e-tags is greater than the ATC for an intertie, the neighbouring transmission providers, currently BC Hydo or SaskPower, will curtail in a priority as determined in accordance with their transmission products and tariffs. If BC Hydro or SaskPower do not curtail enough volume by 15 minutes before the scheduled hour then the AESO curtails

17 Exhibit 0136.01, SaskPower Evidence, May 7, 2012, page 2. 18 http://energy.gov/oe/recovery-act/recovery-act-interconnection-transmission-planning/learn-more-about-

interconnections. 19 Exhibit 0147.02, Enbridge/MATL Evidence, June 15, 2012, page 2. 20 Transcript Volume 7, page 1464. 21 As indicated in OPP 303: Alberta-BC Interconnection Operation, page 1.



transmission schedules on a last-in-first-out (LIFO) basis according to the timing of e-tag approval.22

30. The AESO indicated that with the pending energization of MATL, the AESO must proceed to allocate system ATC in a different fashion by applying a new method to ensure transaction volumes remain within limits. The AESO indicated that if the LIFO method continues to be used, existing interties or certain market participants would likely have an unfair advantage in that they could submit e-tags far in advance of the delivery hour and effectively lock other interties or participants out of the market, and that the LIFO method makes no provision for any future market based signal to be used in the allocation process.23

31. The AESO indicated that the Proposed ATC Rule sets out the requirements and obligations with respect to: the calculation and communication of transfer capability limits, interchange transaction bids and offers, submission and validation of import and export e-tags, scheduling of interchange transactions including schedule changes and dispatches, Saskatchewan inadvertent energy management, and transfer path management including allocation of ATC and interchange transaction curtailment.24

32. The AESO indicated that the Proposed ATC Rule will ensure that ISO rules are in place to appropriately allocate ATC and external operators of transmission facilities cannot be expected to allocate across competing interties. The AESO advised that essential changes in the ISO rules to operational and scheduling provisions were also needed once MATL is energized. As a result, the AESO submitted that it was required to revisit ISO rules Section 6.3.3 and several OPPs, which are listed in Table 1 of this decision.25

33. In developing the Proposed ATC Rule, an AESO consultation process began on May 7, 2010 when the AESO issued the Intertie Framework discussion paper and invited stakeholder comments. The AESO then issued the Intertie Framework recommendation paper on October 7, 2010, followed by the Intertie Framework – Available Transfer Capacity Allocation – Draft Term Sheet on December 16, 2010. On March 17, 2011, the AESO issued a letter of notice requesting comments from stakeholders on proposed ISO rules Section 203.6, and replied to stakeholder comments on July 26, 2011. On September 20, 2011 the AESO issued a letter of notice requesting a second round of comments from stakeholders on proposed ISO rules Section 203.6, and replied to stakeholder comments on November 17, 2011.26

3 Regulatory Framework

3.1 Statutory interpretation

34. Commission consideration of the Proposed ATC Rule requires consideration and interpretation of various provisions of the Electric Utilities Act and sections of the Transmission Regulation made under that legislation, particularly Section 16. As with all such questions of statutory interpretation, the Commission has applied the modern principle of statutory

22 Exhibit 0027.00, AESO Notice of Filing, December 5, 2011, page 2. 23 Exhibit 0145.02, AESO Evidence, June 15, 2012, page 13. 24 Exhibit 0027.00, AESO Notice of Filing, December 5, 2011, page 2. 25 Exhibit 0027.00, AESO Notice of Filing, December 5, 2011, page 2. 26 Exhibit 0062.01, AESO Consultation Record, filed January 20, 2012.



interpretation which requires “the words of an Act be read in their entire context and in their grammatical and ordinary sense harmoniously with the scheme of the Act, the object of the Act and intention of Parliament. When interpreting the plain wording one must pay sufficient attention to the scheme of the act, its object and the intention of the legislature.27

35. As indicated in Sullivan on the Construction of Statutes,28 generally the rules governing the meaning of statutory texts and the types of analysis relied upon by interpreters to determine legislative intent apply equally to regulations. Regulations too must be read in the context of their enabling act, having regard to the language and purpose of the act in general and more particularly the language and purpose of the relevant enabling provisions.29 This is consistent with Section 13 of the Interpretation Act30 providing that interpretation provisions in an enactment apply to regulations made under an enactment.

3.2 Legislation

36. Section 5 of the Electric Utilities Act addresses the purposes of the legislation which include:

(b) to provide for a competitive power pool so that an efficient market for electricity based on fair and open competition can develop, where all persons wishing to exchange electric energy through the power pool may do so on non-discriminatory terms and may make financial arrangements to manage financial risk associated with the pool price;

(c) to provide for rules so that an efficient market for electricity based on fair and open

competition can develop in which neither the market nor the structure of the Alberta electric industry is distorted by unfair advantages of government-owned participants or any other participant;

…

(h) to provide for a framework so that the Alberta electric industry can, where necessary,

be effectively regulated in a manner that minimizes the cost of regulation and provides incentives for efficiency.

37. Section 17 of the Electric Utilities Act imposes on the AESO, inter alia, the duty to:

(a) operate the power pool in a manner that promotes the fair, efficient and openly competitive exchange of electric energy;

(b) to facilitate the operation of markets for electric energy in a manner that is fair and open and that gives all market participants wishing to participate in those markets and to exchange electric energy a reasonable opportunity to do so;

(c) to determine, according to relative economic merit, the order of dispatch of electric energy and ancillary services in Alberta and from scheduled exchanges of electric

27 Rizzo & Rizzo Shoes Ltd. (Re), [1998]1 SCR 27, 154 DLR (4th) 193 at paragraph 21 quoting Driedger in

Construction of Statutes (2nd ed. 1983) at 87 and paragraph 23. 28 Sullivan on the Construction of Statutes, 5th edition, page 368. 29 Bristol-Myers Squibb Co. v. Canada (Attorney General) [2005] 1 SCR 533. 30 Interpretation Act, S.A. 2000, Chapter I-8.



energy and ancillary services between the interconnected electric system in Alberta and electric systems outside Alberta, to satisfy the requirements for electricity in Alberta;

…

(g) provide system access service on the transmission system and to prepare an ISO tariff;

(h) to direct the safe, reliable and economic operation of the of interconnected electric system;

(i) to assess the current and future needs of market participants and plan the capability of the transmission system to meet those needs;

(j) to make arrangements for the expansion of and enhancement to the transmission system;

38. Section 18 of the Electric Utilities Act prescribes that the AESO “must operate the power pool in a manner that is fair, efficient and open to all market participants exchanging or wishing to exchange electric energy through the power pool and that gives all market participants a reasonable opportunity to do so.”

39. Section 20(1) of the Electric Utilities Act states that ISO may make rules respecting, inter alia, the practice and procedures of the Independent System Operator, the operation of the power pool and the exchange of electric energy through the power pool, the operation of the interconnected electric system, and planning the transmission system, including criteria and standards for the reliability and adequacy of the transmission system.

40. Section 20.4 of the Electric Utilities Act describes the circumstances under which a market participant may object to an ISO rule, and Section 20.4(3) describes the onus that such a market participant bears if a hearing is convened to consider the objection:

20.4(3) The market participant filing the notice of objection has the onus of proving

(a) that the Independent System Operator, in making the ISO rule, did not comply with Commission rules made under section 20.9,

(b) that the ISO rule is technically deficient,

(c) that the ISO rule does not support the fair, efficient and openly competitive operation of the market, or

(d) that the ISO rule is not in the public interest

41. Section 33 of the Electric Utilities Act states that the AESO “must forecast the needs of Alberta and develop plans for the transmission system to provide efficient, reliable and non-discriminatory system access service and the timely implementation of required transmission system expansions and enhancements.”

42. Section 8 and 10 of the Transmission Regulation indicate that the AESO must forecast the needs of Alberta and plan the transmission system to meet those needs. Section 15 of the



Transmission Regulation outlines the matters the AESO must take into account when making rules and exercising its duties. Section 16 of the Transmission Regulation imposes an obligation on the AESO to restore capacity on interties that existed on August 12, 2004. Section 17 of the Transmission Regulation states that “[t]he ISO must make rules and establish practices respecting the operation and the management of transmission constraints that may occur from time to time.” And Section 27 of the Transmission Regulation clarifies the cost responsibilities associated with intertie projects.

4 Interties, available transfer capability and access to the Alberta interconnected electronic system

43. Determination of the objections filed regarding the Proposed ATC Rule required the Commission to address the following questions about the nature of ATC and entitlement to access the AIES under Alberta legislation.

4.1 Are interties part of the transmission system and the Alberta interconnected electric system?

44. PowerEx submitted that interties fall within the meaning of “transmission facilities”, but not within the meaning of the “transmission system” or “interconnected electric system”, and that the plain meaning of these definitions is that an intertie is not part of the interconnected electric system in Alberta. Based on this interpretation, PowerEx argued that Section 15 of the Transmission Regulation is not applicable to interties and does not provide the AESO with any guidance with respect to allocation of existing transfer capability on those interties.31

45. Enbridge/MATL counter-argued that the term “interconnected electric system” is defined as “all transmission facilities in Alberta that are interconnected”, and that interties are, by definition, interconnected transmission facilities. Enbridge/MATL submitted that consequently interties “are part of the AIES/transmission system.”32 Enbridge/MATL argued that PowerEx’s interpretation of the term “intertie” would lead to absurd consequences under the Electric Utilities Act and Transmission Regulation, including that the ISO’s duty to direct the safe, reliable and economic operation of the AIES would not apply to the interties; the need identification document process would not apply to interties; allocation of just and reasonable costs of the transmission system to load and exporters would not apply to interties; and several other examples set out in Enbridge/MATL’s submission.33

46. The AESO submitted that a plain reading of the definitions of “transmission system”, “interconnected electric system”, “transmission facility” and “intertie” make clear that interties are part of Alberta’s transmission system and mandate the AESO to include interties when planning for an unconstrained transmission system in accordance with Section 15(e) of the Transmission Regulation.34

31 Exhibit 0271.01, PowerEx Argument, October 15, 2012, page 13. 32 Exhibit 0283.02, Enbridge/MATL Argument, October 29, 2012, page 9. 33 Exhibit 0283.02, Enbridge/MATL Argument, October 29, 2012, pages 10-12. 34 Exhibit 0281.02, AESO Argument, October 29, 2012, page 12.



Commission findings

47. The term “intertie” is defined in the Transmission Regulation as:

1(1)(d) “intertie” means a transmission facility, including its associated components, that links one or more electric systems outside Alberta to one or more points on the interconnected electric system;

48. The terms “interconnected electric system” and “transmission facility” are defined in the Electric Utilities Act as:

1(1)(z) “interconnected electric system” means all transmission facilities and all electric distribution systems in Alberta that are interconnected, but does not include an electric distribution system or a transmission facility within the service area of the City of Medicine Hat or a subsidiary of the City, unless the City passes a bylaw that is approved the Lieutenant Governor in Council under section 138;

1(1)(bbb) “transmission facility” means an arrangement of conductors and

transformation equipment that transmits electricity from the high voltage terminal of the generation transformer to the low voltage terminal of the step down transformer operating phase to phase at a nominal high voltage level of more than 25 000 volts to a nominal low voltage level of 25 000 volts or less, and includes

(i) transmission lines energized in excess of 25 000 volts, … (vi) connections with electric systems in jurisdictions bordering Alberta,

49. The term “transmission system” is defined in the Electric Utilities Act as:

1(1)(ccc) “transmission system” means all transmission facilities in Alberta that are part of the interconnected electric system.

50. The Commission finds that the Alberta portions of the interties are transmission facilities which are physically and electrically connected to the rest of the interconnected electric system and thus are part of the Alberta interconnected electric system and the transmission system as defined in the Electric Utilities Act. As such, the AESO has the same general responsibilities for interties that the AESO has for the interconnected electric system and the transmission system within Alberta. Further, legislative provisions applicable to transmission facilities in Alberta and the interconnected electric system are applicable to Alberta portions of the interties.

4.2 What is the nature of ATC and how is it created?

51. The Proposed ATC Rule provides a method to allocate ATC between interties. Several parties objected to the Proposed ATC Rule on the ground that the Proposed ATC Rule does not reflect the contribution of each individual intertie to Alberta ATC.35 The Commission considers it helpful to clarify the nature of ATC and how ATC is created in dealing with this argument.

35 Exhibit 0129.01, Coalition Policy and Financial Impact Evidence, May 7, 2012, page 26; Exhibit 0152.02,

Coalition Rebuttal Evidence, July 20, 2012, page 12; Exhibit 0271.01, PowerEx Argument, October 15, 2012, page 2; Exhibit 0278.01, Cargill Argument, October 15, 2012, page 2; Exhibit 0272.03, TransCanada Argument, October 15, 2012, page 47.



52. ATCO Power submitted that ATC is created by the interaction of the underlying electric systems in the neighbouring jurisdictions and the interties between jurisdictions. ATCO Power also submitted that to the extent that Alberta load customers have paid and continue to pay for Alberta’s system and for a portion of the interties, Alberta ratepayers have contributed to the creation of ATC.36

53. BC Hydro submitted that ATC is one measure of the ability of an electric system to transfer energy, and it establishes both the commercial and operational limits of an intertie. Further, ATC is distinct from the path rating of an intertie, which is the measure of the physical ability of an intertie to accommodate energy transfers.37

54. NorthPoint submitted that ATC between two systems A and B would be the lowest of (i) the ability of system A to reliably supply exports to system B, (ii) the ability of system B to reliably receive imports from system A and (iii) the thermal capacity of the transmission line(s) connecting the two systems.38

55. PowerEx submitted that the debate about whether an individual party could be said to create ATC was barren, and that it was undeniable that prior to the existing intertie with BC being interconnected, the ATC from BC to Alberta was 0 MW while subsequent to its interconnection ATC has increased to as much as 765 MW.39

56. TransCanada submitted that path ratings for interties within the Western Interconnection are approved by WECC and represent the physical operating capacity of a transmission path, while TTC is the actual operating capacity of the path and may be less than the path rating. Further, TTC reflects the actual volume of energy that can safely flow over a path, is dependent on operating conditions and is therefore non-static.40

57. TransCanada submitted that the AESO currently uses OPP 304: Alberta-BC Interconnection Transfer Limits to describe the process the AESO currently follows when calculating ATC and TTC for the AB-BC intertie, and that system conditions will impact the level of ATC available for the AB-BC intertie.41

58. Enbridge/MATL submitted that Alberta ATC is a result of the entire Alberta network capability, not just the line portion, all of which was funded by Alberta consumers, and that ATC is created by the system.42

59. Enbridge/MATL submitted that tie-lines are a bridge between two systems that enables flows to happen, and that the actual transfer capability is created by all three elements together: the source system, the link or tie, and the destination system. Further, the first time an isolated system gets connected to another system there appears to be a lot of ATC created simply because the isolated system has to be strong on its own to serve all the needs of the generation and loads

36 Transcript Volume 5, pages 1089-1091, and Exhibit 0277.02, ATCO Power Argument, October 15, 2012, page

2. 37 Exhibit 0270.02, BC Hydro Argument, October 15, 2012, page 2. 38 Exhibit 0273.01, NorthPoint Argument, October 15, 2012, page 4. 39 Exhibit 0271.01, PowerEx Argument, October 15, 2012, pages 18-19. 40 Exhibit 0133.01, TransCanada Evidence, May 7, 2012, page 5. 41 Exhibit 0133.01, TransCanada Evidence, May 7, 2012, pages 7-8. 42 Exhibit 0283.02, Enbridge/MATL Argument, October 29, 2012, page 27.



within that system. As subsequent interties are added they start to tax the existing system and there may have to be investment inside the system to increase ATC.43

60. Morgan Stanley submitted that ATC is affected by any changes to the AIES, including the addition of interties, internal transmission, generation and load, and ATC does not have static characteristics but is instead dynamic. This is demonstrated by the fact that since 2005 the amount of ATC in the AIES has declined, when no interties were constructed, and the BC-AB intertie did not contribute to the decline in ATC.44

Commission findings

61. Path rating is defined in the Transmission Regulation as follows:

1(1)(i) “path rating” means the rating of capacity to transfer electric energy assigned to a transmission facility when it was placed in service and rated in accordance with reliability standards in effect at that time;

62. ATC and TTC are not defined in the Electric Utilities Act or the Transmission Regulation. They are terms defined in the AESO’s Consolidated Authoritative Documents Glossary45 as follows (as is TRM):

“available transfer capability” means the remaining transfer capability the ISO determines can be commercially available for transfers over the interconnected transmission network over and above already committed uses, and is calculated as the total transfer capability minus the sum of any applicable transmission reliability margin and existing transmission commitments. “total transfer capability” means the amount of real power the ISO determines can be reliably transferred over the interconnected transmission network under specified system conditions. “transmission reliability margin” means that amount of transfer capability the ISO determines is necessary to ensure the reliable operation of the interconnected electric system taking into account uncertainties in system conditions and the need for operating flexibility.

63. From the definitions of these terms it is evident that the amount of ATC at any point in time is distinct from the path rating of a line and is dependent upon the system conditions and the need for operating flexibility.46

64. Most parties in this proceeding submitted that ATC is a measure of the ability of a system to transfer energy and that the amount of ATC depends on the interaction between neighbouring jurisdictions and the intertie(s) that connect them.47 Not only is this consistent with the defined terms noted above, it is also consistent with the basics of power system dynamics in 43 Transcript Volume 6, pages 1267-1268 and pages 1419-1420. 44 Exhibit 0280.02, Morgan Stanley Argument, October 29, 2012, pages 37-38. 45 The AESO’s Consolidated Authoritative Documents Glossary is an ISO rule, and as such the Electric Utilities

Act provides market participants opportunities to raise concerns with these definitions as a market participant can object to an ISO rule that is filed with the Commission (Section 20.4) or complain about an ISO rule that is in effect (Section 25).

46 Parties in this proceeding have raised issues with the methodology used to calculate the value of these terms, but not the definitions themselves. These issues are addressed later in this decision.

47 Including ATCO Power, BC Hydro, NorthPoint, TransCanada, Enbridge/MATL and Morgan Stanley.



that electric energy cannot be safely and reliability transmitted at a level beyond the safe and reliable limits of what can be provided at one end of a transmission line, received at the other end of the transmission line, or transmitted over the transmission line.

65. Table 2 in OPP 304 indicates different levels of TTC over the AB-BC intertie.48 Further, Table 3 of OPP 304 indicates the TTC levels when various elements of the AIES are out of service. The various TTC levels in OPP 304 do not coincide with the path rating of the AB-BC intertie, but rather is limited by system conditions in Alberta or BC. This reinforces the idea that interties do not create ATC in and of themselves, but rather that ATC is a function of the underlying system(s) and is realized by connecting those systems though an intertie.

66. The submission of Enbridge/MATL are compelling in that the first time an isolated system gets connected to another system there appears to be a considerable amount of ATC created simply because the previously isolated system had to be strong on its own to serve all the needs of the generation and loads within that system. The Commission is further convinced that Alberta ATC has changed between 2005 and the present despite no new interties being constructed.49

67. While there is no doubt that there was no ATC between Alberta and BC prior to energization of the AB-BC intertie, the Commission is not convinced by the argument that the interties created the ATC and are consequently entitled to its benefit in preference to other market participants.

68. The Commission also recognizes that the AESO’s load shed service for imports (LSSi) program, which is separate from the interties and is initiated and operated solely by the AESO, increases the ATC available to the interties. The LSSi program is discussed later in this decision.

69. It is clear to the Commission that ATC is a measure of the ability of an interconnected electric system to transfer electric energy from one jurisdiction to another and is the result of the conditions within each of the interconnected electric systems. The Commission concludes that interties do not in and of themselves create ATC, but rather they enable (up to the path rating of the intertie) the transfer of electric energy between neighbouring interconnected electric systems (up to the transfer capability of each of those interconnected electric systems). The Commission concludes that ATC should be treated as a system resource which does not inure to the benefit of any particular market participant or facility owner.

4.3 How can ATC be allocated?

70. Several parties submitted that the energization of MATL will result in a situation where a simultaneous limit applies to the MATL and AB-BC interties.50

71. TransCanada submitted that Alberta currently has two interties, a synchronous alternating current (AC) connecting Alberta and British Columbia (the AB-BC intertie) and an

48 The AESO witness clarified during the oral hearing that the Import TTC in Table 2 of OPP 304 relates only to

the AB-BC intertie and not the overall Alberta TTC. See Transcript Volume 9, pages 1971-1972. 49 Exhibit 0134.02, BC Hydro Evidence, May 7, 2012, page 4; Exhibit 0280.02, Morgan Stanley Argument,

October 29, 2012, pages 37-38. 50 Exhibit 0129.01, Coalition Evidence, May 7, 2012, page 7; Exhibit 0133.01, TransCanada Evidence, May 7,

2012, page 15; Exhibit 134.02, BC Hydro Evidence, May 7, 2012, pages 10-11; Exhibit 0145.02, AESO Evidence, June 15, 2012, page 7.



asynchronous direct current (DC) intertie connecting Alberta and Saskatchewan. Since the AB-SK intertie employs DC back-to-back technology, it has the capability to control the power flow to predetermined levels independent of contingency events, frequency differences or phase angle differences between the two systems. The proposed MATL intertie will be a synchronous AC intertie connecting Alberta and Montana. TransCanada submitted that the ability to schedule interchange transactions on the AB-SK intertie is not currently, in many cases, limited by the interchange transactions scheduled on the AC interties, but may be limited by internal AIES constraints.51

72. The AESO submitted that where an intertie avoids a simultaneous system limit, that intertie will not be impacted by the allocation contemplated in the Proposed ATC Rule.52

Commission findings

73. The Commission accepts that the AB-BC intertie and the MATL intertie are subject to a simultaneous AC limit, while the AB-SK intertie, due to its physical characteristics, will not be subject to this simultaneous AC limit. All interties, whether AC or DC, are subject to the overall capability of the AIES to transmit and receive electric energy. The physical capabilities of a DC intertie, including the capability to control the power flow to predetermined levels independent of contingency events, frequency differences or phase angle differences between systems, make it independent from other interties such that the ATC from a DC intertie cannot physically be allocated to other interties.

4.4 What is the AESO’s obligation to provide access to the AIES?

74. Market participants wishing to access the AIES from neighbouring jurisdictions and to exchange electric energy through the Alberta power pool or to export electric energy from Alberta must have access to ATC over the interties. There is a finite amount of Alberta ATC available, and with the imminent connection of MATL there must a methodology to allocate ATC between these interties. The Proposed ATC Rule provides an allocation methodology for ATC and regulates access to the AIES. One of the issues in this proceeding relates to the AESO’s obligation to provide access to the AIES.

4.4.1 Access to the AIES

75. PowerEx submitted that the two most important purposes of the Electric Utilities Act in the context of this proceeding are Section 5(b) and Section 5(c), that these purposes of the Electric Utilities Act should inform the AESO’s objectives and activities, and that in developing rules the AESO should provide for the expansion and enhancement of the transmission system in a way which serves these objectives subject to its overriding duties and responsibilities.53

76. Several parties submitted54 that Section 28 and 29 of the Electric Utilities Act provide guidance to the AESO regarding access to the AIES.

51 Exhibit 0133.01, TransCanada Evidence, May 7, 2012, pages 4 and 5. 52 Exhibit 0281.02, AESO Argument, October 29, 2012, page 4. 53 Exhibit 0271.01, PowerEx Argument, October 15, 2012, pages 8-9. 54 AESO in Exhibit 0145.02, AESO Evidence, June 15, 2012, pages 5-7; Enbridge/MATL in Exhibit 0283.02,

Enbridge/MATL Argument, October 29, 2012, pages 19-21.



77. Enbridge/MATL submitted that Section 33 of the Electric Utilities Act sets out how the AESO is to plan the transmission system and requires the AESO to forecast the needs of Alberta and develop plans for the transmission system to provide efficient, reliable and non-discriminatory system access service. Further, the obligation to plan the transmission system to provide non-discriminatory system access service includes providing it to importers of electric energy, which is consistent with Section 8(c) and Section 10(1) of the Transmission Regulation.55

78. Morgan Stanley submitted that Section 17(b) and 17(c) and Section 29 of the Electric Utilities Act and Section 15(1)(e) and 15(1)(f) of the Transmission Regulation require the AESO to ensure that there is sufficient transmission so that all market participants wishing to participate in the electric energy market are able to do so. Further, these sections mean that transmission must be in place to support the overarching purpose of the Electric Utilities Act which is to provide for a competitive power pool so that an efficient market for electricity based on fair and open competition can develop. Morgan Stanley argued that this interpretation is consistent with the Commission’s interpretation of the Electric Utilities Act in AUC Decision 2009-042 and the nature of the Alberta market as an energy-only market with no rights to transmission. Morgan Stanley argued that there is no independent right or property in transmission or capacity that exists in law or can be assigned or allocated as asserted by some of the MPOs in this proceeding.56

79. NaturEner submitted that transmission of energy to or “into” the Alberta energy only market is facilitated through transmission service on the AIES which is a fully regulated monopoly service. Section 28 of the Electric Utilities Act sets out that the AESO is the sole provider of system access service on the AIES, and a market participant cannot have access to the Alberta energy market without access to the AIES. Further, the allocation of ATC or access to the Alberta interchange capability results in access or limitation of access to the Alberta energy market.57

80. NaturEner also submitted that “[i]f access to the AIES is not FEOC, access to the energy market cannot be FEOC.” 58

81. NaturEner further submitted that a monopoly service has the duty to: (a) serve all who ask for service, (b) provide safe and adequate service, and (c) charge only just and reasonable prices, equally to all shippers using the same service.59

82. NaturEner submitted that characterization of the Alberta energy only market as one requiring “no rights” access of in merit electric energy to this market is supported by AUC Decision 2009-042 at paragraph 158.60

83. The AESO submitted that several sections of legislation support treating imports and exports in a similar manner as other supply and demand transactions in the market, including:

55 Exhibit 0283.02, Enbridge/MATL Argument, October 29, 2012, page 12. 56 Exhibit 0280.02, Morgan Stanley Argument, October 29, 2012, pages 4-6. 57 Exhibit 0282.01, NaturEner Argument, October 29, 2012, pages 2-4. 58 Exhibit 0282.01, NaturEner Argument, October 29, 2012, page 23. 59 Exhibit 0282.01, NaturEner Argument, October 29, 2012, page 29. 60 Exhibit 0282.01, NaturEner Argument, October 29, 2012, page 4.



Section 5(b) of the Electric Utilities Act indicates that a power pool should exist where all persons wishing to exchange electric energy can do so on non-discriminatory terms;

Section 17(b) of the Electric Utilities Act sets out the duty on the AESO to facilitate a market that gives all market participants wishing to participate in those markets and to exchange electric energy a reasonable opportunity to do so; and

Section 18(1) of the Electric Utilities Act states the AESO must operate a power pool in a manner that is open to all market participants exchanging or wishing to exchange electric energy.61

84. The AESO submitted that the regulatory scheme also provides support for this approach as indicated in the statement “to the extent possible, industry suppliers with import capacity should be treated the same as intra-Alberta generators.” 62

85. The AESO submitted that several sections of legislation indicate that the AESO is supposed to facilitate open access for interties, including:

Section 29 of the Electric Utilities Act states that the AESO “must provide system access service on the transmission system in a manner that gives all market participants wishing to exchange electric energy and ancillary services a reasonable opportunity to do so”;

Section 15(e) of the Transmission Regulation states that the AESO must plan a transmission system that “is sufficiently robust so that 100% of the time, transmission of all anticipated in-merit electric energy referred to in section 17(c) of the Act can occur when all transmission facilities are in service”;

Section 17(c) of the Electric Utilities Act includes “scheduled exchanges of electric energy and ancillary services between the interconnected electric system in Alberta and electric systems outside Alberta…”; and

Section 15(f) of the Transmission Regulation which states the AESO is to “make arrangements for the expansion or enhancement of the transmission system so that, under normal operating conditions, all anticipated in-merit electricity referred to in clause (e)(i) and (ii) can be dispatched without constraint”.63

Commission findings

86. Section 28 of the Electric Utilities Act states that the ISO “is the sole provider of system access service on the transmission system” and Section 29 states the ISO “must provide system access service on the transmission system in a manner that gives all market participants wishing to exchange electric energy and ancillary services a reasonable opportunity to do so.” System access service is defined in the Electric Utilities Act as “…the service obtained by market participants through a connection to the transmission system, and includes access to exchange electric energy and ancillary services.” The ability to exchange electric energy is facilitated

61 Exhibit 0145.02, AESO Evidence, June 15, 20122, page 5. 62 Exhibit 0145.02, AESO Evidence, June 15, 2012, pages 5-7. 63 Exhibit 0145.02, AESO Evidence, June 15, 2012, pages 5-7.



through the power pool, which is defined in the Electric Utilities Act as “…the scheme operated by the Independent System Operator for (i) exchange of electric energy, and (ii) financial settlement for the exchange of electric energy.” A market participant is defined in the Electric Utilities Act as “…any person that supplies, generates, transmits, distributes, trades, exchanges, purchases or sells electricity, electric energy, electricity services or ancillary services…”

87. The definition of market participant includes a person who transmits electricity or electric energy (an intertie operator) and a person who trades, purchases or sells electricity or electric energy (shippers on the interties). Thus it is clear to the Commission that the AESO’s statutory duty is to provide both intertie operators and shippers with system access service that gives them a reasonable opportunity to access the AIES and by extension to the power pool.

88. In deciding what is a reasonable opportunity the Commission referred to the purpose of the legislation and the duties imposed on the AESO. The purposes of the Electric Utilities Act includes Section 5(b) which states that access to the power pool must be on a non-discriminatory basis to all persons wishing to exchange electric energy, and Section 5(c) further states that the market structure should not be distorted by unfair advantages of government-owned participants or any other participant. However, Section 5 does not further clarify what constitutes a reasonable opportunity for system access.

89. Section 17(i) of the Electric Utilities Act states that the AESO has a duty to plan the transmission system to meet the current and future needs of market participants. Section 33(1) of the Electric Utilities Act states that “[t]he Independent System Operator must forecast the needs of Alberta and develop plans for the transmission system to provide efficient, reliable and non-discriminatory system access service and the timely implementation of required transmission system expansions and enhancements.” Section 33 is clear in that the AESO must plan the transmission system to provide system access service on a non-discriminator basis. However, Section 33 does not further clarify what constitutes a reasonable opportunity for system access.

90. Several parties in this proceeding cited AUC Decision 2009-042 regarding its determination regarding system access for generators to the AIES.64 In Decision 2009-042 the Commission considered sections 17 and 29 of the Electric Utilities Act and determined that there are no explicit or implicit transmission rights, and that access to the AIES, for all generators, is a reasonable opportunity and not a right. In Decision 2009-042 the Commission stated:

158. The Commission is not persuaded by NaturEner’s submission that curtailing new entrants is discriminatory. The AESO stated that new entrants are subject to the results of system impact studies during the planning stage which may indicate the need for some mechanism, such as RAS, to ensure the safety and reliability of the AIES. The Commission has determined that there are no explicit or implicit transmission “rights” but that the obligation imposed on the AESO is to provide market participants with a reasonable opportunity to access the AIES. There is nothing inconsistent with the requirement of a RAS scheme and the provision of a reasonable opportunity to access the AIES where there may be insufficient transmission available.

64 Exhibit 0282.01, NaturEner Argument, October 29, 2012, page 4; Exhibit 0280.02, Morgan Stanley Argument,

October 29, 2012, pages 4-6.



91. Regarding arguments made in this proceeding about treating interties and generators differently,65 the Commission is not persuaded to treat imports and exports differently than other supply and demand transactions in the market, having regard to clear reference in the Electric Utilities Act to Section 5(b) to “all persons wishing to exchange electric energy”, Section 17(b) to “all market participants wishing to participate in those markets” and in Section 18(1) to “all market participants exchanging or wishing to exchange”. The Commission considers the AESO is correct in treating interties in the same manner as generators for the purposes of providing system access service and access to the power pool.

92. The Commission finds a clear legislative requirement to provide non-discriminatory system access service to market participants. The Commission has previously found that there is nothing inconsistent with the requirement of a RAS scheme to ensure the safety and reliability of the AIES and the provision of a reasonable opportunity to access the AIES, and a system that treated all market participants equally. The Commission concludes that a reasonable opportunity for system access service constitutes non-discriminatory access and equal treatment of market participants, subject to any RAS requirements for maintaining safety and reliability of the AIES where there may be insufficient transmission available. The Commission considers this reasonable opportunity for system access applies equally to generators and interties.

4.4.2 Access for anticipated versus scheduled energy

93. ATCO Power submitted that Section 15(1)(e) of the Transmission Regulation obligates the AESO to plan the transmission system taking into consideration the characteristics and expected availability of generating units, and that there is no reference to any obligation to take into consideration the characteristics or availability of any existing or future interties.66

94. ATCO Power submitted that it is only scheduled exchanges of energy that form part of the anticipated in-merit electric energy referred to in Section 17(c) of the Electric Utilities Act, and that the amount of scheduled exchanges is limited by the available ATC. Accordingly, it is not all imports and exports up to the path rating of each intertie that should be anticipated as in-merit electric energy.67

95. ATCO Power submitted that the AESO’s interpretation of Section 15(1)(e) of the Transmission Regulation that the AESO plan the transmission system, including all interties, to be congestion free is contrary to the principle of statutory interpretation as it renders Section 16 of the Transmission Regulation redundant, and that Section 16 of the Transmission Regulation was not a “poke” or “nudge” for the AESO to build unconstrained interties.68

96. PowerEx submitted that the AESO conflated its role with respect to the transmission system as prescribed in Section 15 of the Transmission Regulation, which is expressly internal to Alberta, with its role in respect of interties, in that the AESO believes it is obligated to expand its

65 Exhibit 0142.02, ATCO Power Evidence, May 7, 2012, Appendix 2, pages 2-3; Exhibit 0152.02, Coalition

Rebuttal Evidence, July 20, 2012, pages 17-19; Exhibit 0153.02, TransCanada Rebuttal Evidence, July 20, 2012, page 7.

66 Exhibit 0277.02, ATCO Power Argument, October 15, 2012, pages 8-9. 67 Exhibit 0277.02, ATCO Power Argument, October 15, 2012, pages 8-9. 68 Exhibit 0277.02, ATCO Power Argument, October 15, 2012, pages 8-9.



system so as to accommodate all interties by ensuring that there is available transfer capability sufficient to import all scheduled in-merit electric energy on all interties.69

97. TransCanada submitted that Section 17(c) of the Electric Utilities Act deals with scheduled exchanges of energy, which by their nature have already factored in the limits imposed by ATC. This follows because an interchange transaction is only scheduled if the e-tag has been approved and e-tags are only approved if transmission is available. That is, scheduled exchanges take into account any limits on transmission system and the AESO is not therefore obligated to relieve these limits.70

98. TransCanada submitted that the AESO has misinterpreted its obligation and it is unclear how the AESO interprets Section 15 of the Electric Utilities Act such that it must decongest all interties. TransCanada submitted that Section 15 of the Electric Utilities Act expressly states the AESO’s obligation is to take into consideration the “expected availability of generating units” in planning a 100% in-merit electric energy; however, there is no mention of an AESO requirement to take into consideration the expected availability of interties.71

99. The UCA submitted the AESO appears to interpret scheduled exchanges in Section 17(c) of the Electric Utilities Act to mean before ATC or neighbours’ curtailments are considered; however, a more reasonable interpretation is to consider scheduled from the perspective of the end of the scheduling process after taking into account ATC and neighbouring jurisdictions potential restrictions.72 This interpretation was reflected in an exchange between Mr. Dawson, on behalf of the AESO, and Mr. Sanderson, on behalf of PowerEx, when Mr. Dawson stated “…in terms of calling it scheduled energy, I mean, the AESO wouldn’t allow the final schedule of energy to exceed the simultaneous limit” and “…my understanding is that you can’t have a schedule until all the parties along the path have agreed to implement that schedule.”73

100. Enbridge/MATL argued that under the current rules, imports are usually in-merit. They are bid [offered] in at $0/MWh and will be dispatched before any energy bid [offered] in at a price greater than $0/MWh. If changes are made and imports are allowed to set prices some imports will likely still be in-merit. Further, Section 15(1)(f) dictates that the AESO must not only make a plan providing for all anticipated in-merit imports to be transmitted under normal operating conditions, but it must also arrange for the development of the transmission system to effect this plan.74

101. Enbridge/MATL countered ATCO Power’s argument regarding sections 15 and 16 of the Transmission Regulation by submitting ATCO Power ignores the difference between the tools the ISO has available to it to build an unconstrained transmission system under Section 15, which is generally limited to adding more wires and expanding existing wires, while intertie restoration under Section 16 is not necessarily a function of adding or expanding wires and can be achieved with other options such as LSSi.75

69 Exhibit 0271.01, PowerEx Argument, October 15, 2012, pages 13-14. 70 Exhibit 0272.03, TransCanada Evidence, October 15, 2012, pages 21-22. 71 Exhibit 0272.03, TransCanada Evidence, October 15, 2012, page 21. 72 Exhibit 0275.01, UCA Argument, October 15, 2012, page 16. 73 Transcript Volume 9, page 1948. 74 Exhibit 0283.02, Enbridge/MATL Argument, October 29, 2012, pages 13-15. 75 Exhibit 0283.02, Enbridge/MATL Argument, October 29, 2012, pages 13-15.



102. The AESO argued that Section 15(1)(e) and 15(1)(f) of the Transmission Regulation require the AESO to plan and make arrangements for a congestion free transmission system for all anticipated in-merit electric energy, and that the definition of anticipated should apply unless the application of the literal rule would lead to an absurdity, saying it does not. Further, in fulfilling its duty to plan for an unconstrained transmission system, the AESO must take notice of the fact that there is underutilized transmission capacity on the interties due to system limitations that restrict imports and exports.76

103. The AESO argued77 that ATCO Power’s contention that only scheduled exchanges referred to in Section 17(c) of the Electric Utilities Act are to be considered anticipated in-merit electric energy leads to the incorrect conclusion that system limits are able to drive ATC on the interties to zero, and that zero would be an appropriate level of anticipated in-merit energy for planning purposes. Further, in light of Alberta’s market design this could not have been the intent of the legislation and that anticipated in-merit energy includes not only the energy that actually flows, but also the energy that can reasonably be expected to flow, which in this context is comprised of those transactions affected by ATC limits.

104. The AESO said78 that it interprets the legislation and regulatory scheme to require that imports and exports up to the path rating of each intertie should be considered as anticipated in-merit electric energy and argued that the AESO thus has an obligation to plan the transmission system so that every intertie (both existing and future) can simultaneously transfer up to its path rating.

Commission findings

105. If a market participant has made an investment in infrastructure in order to connect to the AIES, for example an intertie, it is clear to the Commission that the market participant wishes to exchange electric energy with the AIES. In providing system access service the AESO must meet its legislated requirements regarding all in-merit or scheduled electric energy while also taking into account electric energy that is reasonably expected to be in-merit or scheduled. In this regard the Commission sees no distinction between an intertie and a generator.

106. Section 15 of the Transmission Regulation states:

15(1) In making rules under section 20 of the Act, and in exercising its duties under sections 17 and 33(1) of the Act, the ISO must:

…

(e) taking into consideration the characteristics and expected availability of generating units, plan a transmission system that

(i) is sufficiently robust so that 100% of the time, transmission of all anticipated in-merit electric energy referred to in section 17(c) of the Act can occur when all transmission facilities are in service, and

76 Exhibit 0281.02, AESO Argument, October 29, 2012, pages 11-12. 77 Exhibit 0281.02, AESO Argument, October 29, 2012, pages 11-12. 78 Exhibit 0145.02, AESO Evidence, June 15, 2012, pages 5-7.



(ii) is adequate so that, on an annual basis, and at least 95% of the time, transmission of all anticipated in-merit electric energy referred to in section 17(c) of the Act can occur when operating under abnormal operating conditions,

(f) make arrangements for the expansion or enhancement of the transmission system so that, under normal operating conditions, all anticipated in-merit electricity referred to in clause (e)(i) and (ii) can be dispatched without constraint, and

107. Section 17 of the Electric Utilities Act states:

17 The Independent System Operator has the following duties: …

(c) to determine, according to relative economic merit, the order of dispatch of electric energy and ancillary services in Alberta and from scheduled exchanges of electric energy and ancillary services between the interconnected electric system in Alberta and electric systems outside Alberta, to satisfy the requirements for electricity in Alberta;

108. The legislated requirement rests with the AESO to plan the transmission system, which is done in stages and may take time to construct and energize, in order to provide non-discriminatory system access service to the market participant and a reasonable opportunity to exchange electric energy.

109. The Commission considers that Section 15 the Transmission Regulation speaks to the performance criteria that the AESO must meet when planning and constructing the transmission system and does not limit the AESO’s requirement to provide non-discriminatory system access service and a reasonable opportunity to exchange electric energy. The performance criteria in Section 15 simply provide a goal to measure the AESO’s performance in meeting the requirements of Section 16 and does not render Section 16 of the Transmission Regulation redundant, as argued by ATCO Power.

5 Grounds for Objections

110. The Commission has discussed the issues in the following order, based largely on the order provided by several of the MPOs. However, the Commission has considered the issues in all contexts when determining whether the MPOs have met the onus of proving the Proposed ATC Rule is technically deficient, does not support the fair, efficient and openly competitive operation of the market, or is not in the public interest.

5.1 Rule does not support the FEOC operation of the market

111. Parties submitted that the Proposed ATC Rule does not support the fair, efficient and openly competitive operation of the market because the Proposed ATC Rule:

(a) Provides incorrect economic incentives;

(b) Impedes open competition;

(c) Fails to align with existing AESO practices;

(d) Fails to align with existing North American practices;



(e) Negatively impacts pool price;

(f) Leads to increased bookout fees;

(g) Impacts parties with firm transmission rights in other jurisdictions; and

(h) Was not finalized when an investment decision was made.

5.1.1 Economic incentives

Dynamic signal/investment signal

112. Several parties in this proceeding indicated that the Proposed ATC Rule is not efficient because it does not send a market signal or provide an appropriate economic incentive that will encourage investment in new interties that result in increased transfer capacity as opposed to displacing existing capacity.79

113. PowerEx submitted that Government policy firmly established through legislation and regulation that interties are to be restored to their 2004 capacity whether or not the Commission or anyone else considers that to be economically efficient.80

114. The Coalition submitted the Proposed ATC Rule creates a perverse incentive by encouraging the builders of new transmission facilities to develop transmission projects without creating new transmission capacity.81

115. TransCanada submitted that since the Proposed ATC Rule derogates from existing firm transmission service, new interties will likely be unable to sell the firm transmission rights elsewhere that is required to finance the investment in the new intertie,82 and that requiring new merchant interties to invest in creating incremental Alberta interchange capability (AIC)83 coincident with any sale of firm transmission service will send the proper investment signal.84

116. PowerEx submitted that the development of ATC for either new or existing interties may require transmission investments outside Alberta, and that the Proposed ATC Rule relies on the AESO to make the necessary investments to create intertie ATC which inefficiently limits such investments to the geographical constraints of Alberta.85

79 Exhibit 0142.02, ATCO Power Evidence, May 7, 2012, page 8; Exhibit 0129.01, Coalition Policy and Financial

Impact Evidence, May 7, 2012, pages 2-3; Exhibit 0050.00, PowerEx Objection, December 19, 2011, page 6; Exhibit 0133.01, TransCanada Evidence, May 7, 2012, pages 21-22; Exhibit 0138.01, TransCanada (Roach) Evidence, May 7, 2012, pages 6-7; Exhibit 0153.02, TransCanada Rebuttal Evidence, July 20, 2012, page 3; Exhibit 0275.01, UCA Argument, October 15, 2012, pages 8-9.

80 Exhibit 0271.01, PowerEx Final Argument, October 15, 2012, page 23. 81 Exhibit 0129.01, Coalition Policy and Financial Impact Evidence, May 7, 2012, page 12. 82 Exhibit 0133.01, TransCanada Evidence, May 7, 2012, pages 21-22. 83 AIC is defined in the AESO’s Consolidated Authoritative Documents Glossary as “the amount of interconnected

electric system transmission capability that the ISO determines is available for allocation to all transfer paths, after subtracting amounts for relevant factors including system operating limits, generating capacity and Alberta internal load.”

84 Exhibit 0153.02, TransCanada Rebuttal Evidence, July 20, 2012, page 6. 85 Exhibit 0271.01, PowerEx Argument, October 15, 2012, page 31.



117. The AESO, Enbridge/MATL and NaturEner submitted that the facts indicate that the Proposed ATC Rule does send an appropriate investment signal for new interties as the parties who are currently building a new intertie (and most likely to construct additional intertie capacity) support the Proposed ATC Rule.86 In addition, the AESO submitted that the Proposed ATC Rule creates an incentive to make a new intertie additive, because an intertie that avoids a simultaneous ATC limit is not subject to the sharing of ATC.87

118. Enbridge/MATL submitted during the hearing that “…in the case of MATL proper, if they had adopted a configuration that included, for example, the AC-DC-AC converter and added $120 million of additional costs to the project, it wouldn’t have been viable.”88

119. Morgan Stanley submitted that the Proposed ATC Rule will increase competition for imports into Alberta as it will bring an additional measure of discipline to the Alberta import market and increased liquidity in the forward market.89

Static efficiency

120. PowerEx submitted that Alberta is interested in the aggregate use of the interties because it makes no difference to the Alberta pool price which intertie actually supplies that aggregated power and that the only material difference from an economic efficiency perspective between the Proposed ATC Rule and the capacity contribution approach advocated by the Coalition, PowerEx and TransCanada relates to dynamic efficiency.90

121. PowerEx, TransCanada, NorthPoint and Cargill submitted that they have objected to the Proposed ATC Rule in favour of an alternative rule, which is consistent with their belief that their opportunity to trade with Alberta will be enhanced, not diminished, if their access to both interties is determined under the Capacity Contribution Approach91 rather than the Proposed ATC Rule.92

122. Enbridge/MATL submitted that under the Proposed ATC Rule there is the potential risk for pro rata reduction in transactions across each intertie, but traders on either intertie will face an equal risk of reduction regardless of the path upon which they are trading (approximately a one-third reduction) which can be managed. Further, intertie developers can determine with sufficient certainty how much ATC will be available to proceed with a project.93

123. Morgan Stanley submitted that a proper evaluation of the Proposed ATC Rule cannot be limited to a static analysis in a single hour. Morgan Stanley submitted the Proposed ATC Rule will result in positive short-term economic efficiency through discipline amongst traders

86 Exhibit 0281.02, AESO Argument, October 29, 2012, pages 19-20; Exhibit 0283.02, Enbridge/MATL Argument,

October 29, 2012, pages 32-34; Exhibit 0282.01, NaturEner Argument, October 29, 2012, pages 25-26. 87 Transcript Volume 8, page 1712; Exhibit 0281.02, AESO Argument, October 29, 2012, page 23. 88 Transcript Volume 6, September 18, 2012, page 1331. 89 Exhibit 0280.02, Morgan Stanley Argument, October 29, 2012, pages 54-55. 90 Exhibit 0271.01, PowerEx Argument, October 15, 2012, page 29. 91 PowerEx clarified that the capacity contribution approach considers the extent to which the energization of a new

intertie increase the ATC of the AIES, such that ATC is allocated based on the capacity contribution of each intertie. See Exhibit 0271.01, PowerEx Argument, October 15, 2012, page 3 and page 24.

92 Exhibit 0271.01, PowerEx Argument, October 15, 2012, page 29; Exhibit 0278.01, Cargill Argument, October 15, 2012, page 2.

93 Exhibit 0283.02, Enbridge/MATL Argument, October 29, 2012, pages 28-29.



resulting from repeated competition, rather than static competition in a single hour, on all interties to use the capacity allocated to the intertie when there is a price spread between the Alberta and US markets. Further, this discipline will only increase as the number of constrained hours increases.94

SATL considerations

124. Several parties in this proceeding indicated that the development of the Saskatchewan Alberta Transmission Line (SATL) will be less likely to proceed if it cannot preserve access to any ATC that results from SATL,95 or that SATL may reasonably expect the Alberta system to pay for those facility costs that enable the intertie to increase ATC.96

125. Morgan Stanley argued that SATL intervened in this proceeding and chose not to participate, and as a result there is no basis to infer what SATL’s views are in respect of the Proposed ATC Rule and its effects.97

126. SATL submitted that it is in the process of developing a bi-directional 150 MW AC-DC-AC converter station to interconnect the SaskPower transmission grid to the AIES near Lloydminster, and that SATL did not intend to, nor did it, file in support of any MPOs or the AESO as SATL’s position is that a DC interconnection as proposed by SATL will not adversely impact the existing nor future ATC allocation on Alberta’s interties.98

Commission findings

Dynamic signal/investment signal

127. An ATC allocation methodology that requires new interties to create or add incremental ATC would send a different investment signal than the Proposed ATC Rule. The Commission considers the investment signal under the Proposed ATC Rule treats all market participants equally in that if any intertie developer wishes to capture the full benefit of resulting ATC up to its path rating it will have the option to invest in various technologies or methods that ensure such an outcome,99 but is not required to make such investments in order to connect to the AIES for system access service.

128. The Commission is not convinced that under the Proposed ATC Rule new intertie developers may not be able to sell firm transmission rights to finance their project as the construction of the MATL intertie is evidence to the contrary. The Commission accepts that the

94 Exhibit 0280.02, Morgan Stanley Argument, October 29, 2012, pages 25-26. 95 Exhibit 0273.01, NorthPoint Argument, October 15, 2012, page 15; Exhibit 0274.01, SaskPower Argument,

October 15, 2012, page 5. 96 Exhibit 0272.03, TransCanada Argument, October 15, 2012, pages 12-13. 97 Exhibit 0280.02, Morgan Stanley Argument, October 29, 2012, page 49. 98 Exhibit 0057.01, Saskatchewan Alberta Tie Line Statement of Intent to Participate, January 11, 2012. 99 In this proceeding there was considerable evidence presented on various technologies that could be installed on

the MATL intertie that would make it no longer subject to a simultaneous limit with the AB-BC intertie. Some of these technologies included an AC-DC-AC converter station or an HVDC transmission line, and there may be other options. The Commission does not consider it necessary to investigate any of these options as they are outside the scope of this proceeding, which is to determine the merits of the Proposed ATC Rule for allocating ATC.



MATL intertie would likely not have been constructed if there was a requirement for incremental ATC with a new intertie.100

129. The Commission finds that development of more interties and import capacity and the resulting prospects of increased power supply in the future from outside Alberta is more likely to achieve greater economic efficiency in the Alberta power market. Further, it is likely to result in public benefit for the consumers through increased competition.

130. The Commission is not persuaded that the dynamic economic effect of the Proposed ATC Rule will be to decrease future intertie development or promote future intertie development without investing in facilities resulting in additional ATC.

131. Regarding PowerEx’s submission that the Proposed ATC Rule will inefficiently limit investments to create intertie ATC to within the geographical borders of Alberta, the Commission refers to the unchallenged evidence of BC Hydro that since 2003 the constraints responsible for limiting Alberta ATC have been sourced in Alberta approximately 90% of the time for imports and approximately 93% of the time for exports.101 With this information it appears Alberta could do more to relieve the constraints on import and export ATC.

Static efficiency

132. The Commission recognizes that under the current market rules in any instant in time the Alberta pool price is indifferent to which intertie delivers the required energy. The Commission also agrees under the Proposed ATC Rule the potential risk for pro rata reduction would effectively be shared equally between interties that share simultaneous limits, that traders on those interties can make a reasonable estimate of their expected flows and that through repeated competition traders will discipline each other for unused capacity.

SATL considerations

133. The Commission recognizes there are potentially differences in the facility requirements for MATL and SATL as the MATL interconnection joins two jurisdictions within the WECC, while SATL is proposed to join the WECC (part of NERC’s Western Interconnection) and the MRO (part of NERC’s Eastern Interconnection). These differences have not been established in this proceeding. The Commission finds the evidence of the likely impact of the Proposed ATC Rule on the SATL project to be inconclusive.

134. The Commission is not persuaded that the Proposed ATC Rule does not support the FEOC operation of the market on this basis.

100 Transcript Volume 6, September 18, 2012, page 1331; Exhibit 0283.02, Enbridge/MATL Argument, October 29,

2012, pages 32-34. 101 Exhibit 0134.02, BC Hydro Evidence, May 7, 2012, page 4.



5.1.2 Open competition considerations

Race to zero

135. Several parties submitted that the Proposed ATC Rule will effectively result in participants offering their energy at $0/MWh (referred to as the race to zero), which some argued was not an outcome that supports the FEOC operation of the market.102

136. Morgan Stanley and the AESO submitted that the race to zero is a legitimate market response and is no more or no less than a demonstration of competition.103 In addition, the AESO submitted this form of competition is no different than the strategy employed today by many generators in Alberta, often comprising more than half of total supply.104

Allocation to the interties or to the shippers

137. ATCO Power submitted that in order to allocate ATC based on the offers received by the AESO, the AESO must deal directly with the shippers on the interties rather than with the interties themselves because by failing to deal directly with pool participants the reverse merit order provision under the Proposed ATC Rule presents opportunities for withholding and will lead to arbitrary, unfair and inefficient import/export transactions.105 ATCO Power also submitted that non-firm shippers can offer their energy on the BC intertie which will impact the allocation between the AB-BC intertie and MATL. ATCO Power submitted that the offers from non-firm shippers, which are unlikely to ever be scheduled, can impact the allocation of ATC among the other shippers which is an example of an unfair and arbitrary result.106

138. Morgan Stanley submitted that if the Proposed ATC Rule is not confirmed and another rule which allows for the de facto creation of property rights is implemented, the message to the marketplace is that the Alberta market is closed to new entrants.107 Conversely, the AESO submitted that investors in MATL have confirmed that they consider the Proposed ATC Rule to welcome competitive supply sources to Alberta.108

Subsidy from existing interties to new interties

139. Several parties submitted that the Proposed ATC Rule amounts to a subsidization from interties that create ATC to those that do not, which they argue is inefficient, unfair and counter to open competition.109

102 Exhibit 0142.02, ATCO Power Evidence, May 7, 2012, Appendix 1, pages 1-2; Exhibit 0277.02, ATCO Power

Argument, October 15, 2012, pages 10-12; Exhibit 0129.01, Coalition Policy and Financial Impact Evidence, May 7, 2012, page 25; Exhibit 0055.00, NorthPoint Objection, December 19, 2011, page 5; Exhibit 0273.01, NorthPoint Argument, October 15, 2012, page 18; Exhibit 0272.03, TransCanada Argument, October 15, 2012, pages 48-49; Exhibit 0153.02, TransCanada Rebuttal Evidence, July 20, 2012, page 12.

103 Exhibit 0280.02, Morgan Stanley Argument, October 29, 2012, page 21; Exhibit 0281.02, AESO Argument, October 29, 2012, pages 17-18.

104 Exhibit 0281.02, AESO Argument, October 29, 2012, pages 17-18. 105 Exhibit 0277.02, ATCO Power Argument, October 15, 2012, page 14. 106 Exhibit 0277.02, ATCO Power Argument, October 15, 2012, pages 11-12. 107 Exhibit 0144.02, Morgan Stanley Capital Group Evidence, June 15, 2012, pages 3-4. 108 Exhibit 0281.02, AESO Argument, October 29, 2012, page 22. 109 Exhibit 0156.03, ATCO Power Rebuttal Evidence, July 20, 2012, page 9; Exhibit 0278.01, Cargill Argument,

October 15, 2012, page 2; Exhibit 0272.03, TransCanada Evidence, October 15, 2012, page 44.



140. Morgan Stanley submitted that ATCO Power’s cross subsidy concept is actually rent dissipation that would occur as new market players compete with incumbents and is a result of and indication of competition.110

Commission findings

Race to zero

141. The Commission recognizes that in the Alberta wholesale electricity market there are multiple market participants that offer their energy in at $0/MWh, as noted by the AESO, and that the Alberta wholesale electricity markets is a competitive market. Further, in this market the pool price does, on occasion, settle at $0/MWh. The Commission is not convinced by suggestions that a race to zero does not support the fair, efficient and openly competitive operation of the market.

Allocation to the interties or to the shippers

142. Regarding ATCO Power’s submissions that the AESO not dealing directly with shippers on the interties may lead to arbitrary, unfair and inefficient results, the Commission considers the AESO has no other option available. In the absence of a pricing mechanism for intertie transactions the AESO has no way to distinguish between shippers on a given intertie. With no transmission rights in Alberta there is no means for the AESO to recognize the transmission rights of a shipper in a neighbouring jurisdiction. Under the current market rules the Commission considers that Proposed ATC Rule properly prescribes dealing with the intertie operators rather than with the shippers on the interties.

Subsidy from existing interties to new interties

143. As mentioned previously in this decision the Commission considers that ATC should be treated as a system resource accessible to users on a non-discriminatory individual basis. As there is no ATC belonging to any existing intertie to be transferred to a new entrant it cannot be considered a subsidy.


5.1.3 Rule fails to alight with existing AESO practices

145. Several parties in this proceeding argued that the AESO’s use of the transmission constraints management (TCM) principles, which were approved by the Commission in AUC Decision 2009-042, were intended to apply for real-time unforeseen congestion that is infrequent and of short duration, and should not apply for the Proposed ATC Rule because ATC allocation is neither infrequent or of short duration.111

110 Exhibit 0280.02, Morgan Stanley Argument, October 29, 2012, pages 44-45. 111 Exhibit 0051.00, ATCO Power Objection, December 19, 2011, page 2; Exhibit 0142.02, ATCO Power Evidence,

May 7, 2012, Appendix 2, pages 2-3; Exhibit 0156.03, ATCO Power Rebuttal Evidence, July 20, 2012, page 5; Exhibit 0152.02, Coalition Rebuttal Evidence, July 20, 2012, pages 16-17; Exhibit 0272.03, TransCanada Argument, October 15, 2012, pages 31-32; Exhibit 0153.02, TransCanada Rebuttal Evidence, July 20, 2012, page 11.



146. PowerEx submitted the AESO has established policies for dealing with generation and load interconnection requests where a proposed connection will cause or exacerbate an existing constraint on the AIES in that the AESO may assign and utilize a remedial action scheme, and the customer can choose to either accept the RAS as a condition to interconnect or decline service until the system is reinforced.112

147. The Coalition and TransCanada indicated that with respect to the wind power management rule (WPM Rule), only wind facilities are subject to the pro rata curtailments and not other generation sources. This is consistent with both the cost causation principle, in recognition that ramping events are caused by wind facilities and not other generators, and the fairness principle whereby equals are treated equally and unequals are treated unequally.113

148. The Coalition submitted that the AESO’s system access policy, as described in a February 28, 2012 letter from the AESO to the AUC, gives priority to existing customers over new customers whose impending interconnection would cause or exacerbate transmission congestion. In addition, providing MATL conditional access to the AIES such that the combined AB-BC intertie and MATL intertie transfer capability limit is not exceeded by flows over the interconnection is consistent with the AUC Decision 2009-042 ruling that conditional access to a new participant constitutes reasonable access when it causes transmission constraints.114

149. NaturEner submitted that access to the AIES is determined based on relative economic merit, and where energy offers at the same price are both in merit a pro rata determination grants non-discriminatory access without giving preferential rights to one party or another to access Alberta’s energy only market. Further, this concept has been established and is currently used in the TCM Rule, WPM Rule, and the AESO’s supply surplus rule.115

150. The AESO submitted that the Proposed ATC Rule does not differ from current practice with respect to the consideration given to firm transmission rights held on the other side of the border; neither current practice nor the Proposed ATC Rule give them consideration.116 The AESO submitted that the Proposed ATC Rule and the TCM Rule use economic dispatch following the merit order as contemplated in Section 17(c) of the Electric Utilities Act, and that the Proposed ATC Rule, the TCM Rule and the WPM Rule all employ pro rata calculations in situations where energy offer price cannot be used to differentiate among transactions.117

151. Further, the AESO indicated aspects of the current ISO rules are found in the Proposed ATC Rule, including curtailment that is done by LIFO ahead of time and by pro rata during the delivery hour with no regard to the existence of firm/non-firm transmission rights in other jurisdictions. Also, exports are curtailed real time on a pro rata basis if necessary, and import opportunity service and export opportunity service do not provide preferential access, rollover rights seniority or the ability to sell in a secondary market.118

112 Exhibit 0050.00, PowerEx Objection, December 19, 2011, pages 7-8. 113 Exhibit 0152.02, Coalition Rebuttal Evidence, July 20, 2012, pages 16-17; Exhibit 0272.03, TransCanada

Argument, October 15, 2012, pages 29-32. 114 Exhibit 0129.01, Coalition Policy and Financial Impact Evidence, May 7, 2012, page 19. 115 Exhibit 0282.01, NaturEner Argument, October 29, 2012, page 4. 116 Exhibit 0145.02, AESO Evidence, June 15, 2012, page 16. 117 Exhibit 0145.02, AESO Evidence, June 15, 2012, pages 10-11. 118 Exhibit 0145.02, AESO Evidence, June 15, 2012, pages 15-16



Commission findings

152. The AESO has not indicated that the Proposed ATC Rule will apply to situations where there is real-time unforeseen congestion that is infrequent and short duration, as it did in Proceeding ID No. 41 concerning the TCM Rule. Rather, the AESO has indicated the Proposed ATC Rule will employ pro rata calculations in situations where energy offer price does not differentiate among transactions. The Commission does not find this inconsistent with the TCM Rule or to be unfair or technically deficient.

153. In considering other existing AESO practices using pro rata allocations, as identified by NaturEner, ISO rules Section 202.5: Supply Surplus (ISO rules Section 202.5), which is currently in effect, states at Section 2(2) that the AESO, when considering a supply surplus situation, must follow certain procedures including “(d) issue, on a pro rata basis: (i) dispatches to generating units for partial volumes of flexible blocks of the zero dollar ($0) offers; and (ii) directives to any available wind aggregated generating facilities.” In addition, the Commission recognizes that ISO rules Section 202.3: Issuing Dispatches for Equal Prices (ISO rules Section 202.3), which is currently in effect, states that for equal priced operating block the ISO can issue dispatches on a pro rata basis. Finally, OPP 303: Alberta-BC Interconnection Operation, which is currently in effect (as part of its application for the Proposed ATC Rule the AESO proposes to remove this OPP) states “if schedule curtailments are required within the hour on the Alberta-BC interconnection, they must be carried out on a pro-rata basis, if the reason for the curtailment originates in Alberta.” The Commission considers that the pro rata allocation in the Proposed ATC Rule is consistent with these ISO rules.

154. The Proposed ATC Rule allocates ATC between interties on a pro-rata basis, which the Commission finds treats them equitably in terms of their right to access the AIES. The Commission considers this is consistent with the principles set out in the WPM Rule which treats all wind generators equally.

155. Regarding the AESO policy and practice of requiring new entrants to install a RAS scheme, the Commission accepts the testimony of the AESO that the MATL intertie will be equipped with a RAS scheme as set out in the pending WECC system studies.119 The Commission finds this is a reasonable opportunity for system access service which is non-discriminatory access and equal treatment of market participants, subject to any RAS requirements for maintaining safety and reliability of the AIES where there may be insufficient transmission available.

156. The AESO’s February 28, 2012 letter to the AUC indicates that the option that reflects the practice that is most closely followed at the current time is that the AESO would connect market participants as long as (i) there is an ability to compete; (ii) the system remains operable; and (iii) there is a plan to fix any existing constraints on the system.120 Upon a plain reading of the February 28, 2012 letter from the AESO to the AUC the Commission does not agree with the Coalition’s interpretation that the AESO’s system access policy gives priority to existing customers over new customers.

119 Exhibit 0062.01, AESO Intertie Framework Recommendation Paper, p. 14-15 (tile 130 of the exhibit); Exhibit

0145.02, AESO Evidence, June 15, 2012, pages 19-21. 120 Exhibit 0209.01, PowerEx’s submission of AESO’s February 28, 2012 letter to AUC, page 3.




5.1.4 Rule fails to align with existing North American practices

158. Several parties in this proceeding indicated that jurisdictions throughout North America require that new transmission facility interconnection do not have a negative commercial or reliability impact on the transfer capability of existing facilities, also known as priority to existing firm transmission customers or the hold harmless principle.121

159. The Coalition submitted that the AESO’s existing policy provides de facto firm service priority to existing customers with firm service rights outside Alberta on interconnected systems and that ATC for imports and exports is currently allocated to those with firm service rights on the other side of the interconnection. Further, the Coalition submitted that the AESO should continue to honor firm service rights granted in other jurisdictions by treating such rights holders as a common class and assessing priority within the class in the same manner as it does other classes. This means that when there is a new entrant to the class the new entrant assumes the burden of the foreseeable outages it creates and unforeseeable outages are handled on a pro rata basis.122

160. The Coalition submitted the nature of opportunity service is not relevant to this proceeding because this proceeding is concerned with the allocation of ATC between interties and not between market participants. Opportunity service applies to the market participants transacting over the interties and not to the interties themselves.123

161. NorthPoint and TransCanada submitted that a recent British Columbia Utilities Commission (BCUC) decision indicated that the British Columbia Transmission Corporation (BCTC), now BC Hydro,124 should respect the system constraints in Alberta when selling firm transmission, and there is a responsibility on a control area to account for restrictions in other jurisdictions when allocating intertie usage.125

162. TransCanada provided several Federal Energy Regulatory Commission (FERC) precedents which consistently respected the rights of existing firm customers,126 and the granting of increased transfer capability to those customers that pay for network upgrades.127 In addition, TransCanada cited Canadian precedent in the Regie de l’energie decision128 in Quebec that acknowledged that existing firm customers had a priority right under the rollover provisions of Hydro Quebec’s tariff.


PowerEx Argument, October 15, 2012, page 31; Exhibit 0273.01, NorthPoint Argument, October 15, 2012, page 17; Exhibit 0131.01, TransCanada (Musco) Evidence, May 7, 2012, pages 5-6.

122 Exhibit 0129.01, Coalition Policy and Financial Impact Evidence, May 7, 2012, page 19. 123 Exhibit 0152.02, Coalition Rebuttal Evidence, July 20, 2012, page 5. 124 BCUC Order G-103-09, September 10, 2009. 125 Exhibit 0055.00, NorthPoint Objection, December 19, 2011, page 4; Exhibit 0133.01, TransCanada Evidence,

May 7, 2012, pages 23-24; Exhibit 0138.01, TransCanada (Roach) Evidence, May 7, 2012, pages 5-6. 126 Exhibit 0131.01, TransCanada (Musco) Evidence, May 7, 2012, pages 10-12. 127 Exhibit 0131.01, TransCanada (Musco) Evidence, May 7, 2012, pages 19-21. 128 Regie de l’Energie, Quebec, D-2010-160, December 20, 2010.



163. Enbridge/MATL submitted that payment of export opportunity service (XOS) or import opportunity service (IOS) under the ISO tariff does not secure a transmission path across the provincial border. Further, XOS and IOS are not firm service, they are not comparable to the FERC contract path concept, and they are not point to point.129

164. Regarding FERC precedent, Enbridge/MATL submitted that it is not applicable as the FERC regime involves firm transmission customers, which do not exist in Alberta.130 Enbridge/MATL submitted the Regie de l’energie case is different from this proceeding because both parties in the Regie case had firm transmission service on both sides of the interconnect.131

165. Further, Enbridge/MATL indicated that there is a difference between physical and financial rights in regard to existing facilities. Regarding physical rights, a new transmission facility should not affect the reliability of the system to which it connects, as the WECC would require for a new intertie. However, Enbridge/MATL submitted the hold harmless principle should not be extended beyond reliability matters to include commercial impacts.132 and that suppliers outside the Alberta grid have historically not paid for and received firm transmission rights on the Alberta grid.133

166. Morgan Stanley submitted that the vesting of de facto property rights is contrary to the Alberta market design and if accepted will deter new entrants,134 and disputed the notion that any transmission rights created and existing in BC and Saskatchewan through their respective market designs should take paramountcy over the Alberta market design legislated under the Electric Utilities Act.135

167. The AESO submitted the BCUC decision cited is not relevant as it pertains to selling additional firm transmission rights elsewhere in a jurisdiction that has a system of explicit transmission rights, which is not the case in Alberta.136

168. The AESO submitted the FERC principles regarding recognition of existing firm rights are not a relevant consideration in this proceeding because there are no firm transmission rights for intertie transactions in Alberta and no recognition of firm transmission rights purchased outside of Alberta. Transmission access historically enjoyed by market participants into or out of Alberta across currently existing interties has never been represented nor treated as firm on the Alberta side of the border.137

Commission findings

169. In Decision 2009-042 the Commission determined that there are no explicit or implicit transmission rights, and that generators are only entitled to reasonable access to the AIES on a non-discriminatory basis. Previously in this decision the Commission has determined that access 129 Exhibit 0147.03, Enbridge/MATL (Stout) Evidence, June 15, 2012, page 15. 130 Exhibit 0150.02, Enbridge/MATL (Craig Baker) Evidence, June 15, 2012, pages 10-11. 131 Exhibit 0150.02, Enbridge/MATL (Craig Baker) Evidence, June 15, 2012, page 16. 132 Exhibit 0150.02, Enbridge/MATL (Craig Baker) Evidence, June 15, 2012, page 6; Exhibit 0283.02,

Enbridge/MATL Argument, October 29, 2012, pages 37-38. 133 Exhibit 0150.02, Enbridge/MATL (Craig Baker) Evidence, June 15, 2012, page 6. 134 Exhibit 0144.02, Morgan Stanley Capital Group Evidence, June 15, 2012, page 3. 135 Exhibit 0280.02, Morgan Stanley Argument, October 29, 2012, page 30. 136 Exhibit 0145.02, AESO Evidence, June 15, 2012, pages 15-16. 137 Exhibit 0145.02, AESO Evidence, June 15, 2012, pages 15-16.



which is subject to RAS requirements for maintaining safety and reliability of the AIES still constitutes reasonable access where there may be insufficient transmission available and that the requirement applies equally to generators and interties.

170. While the Commission considers the nature of opportunity service is not at issue in this proceeding, the Commission finds the nature of opportunity service to be informative. Within the AESO tariff importers and exporters are charged for access to the transmission system based on the Rate ISO Import Opportunity Service and Rate XOS Export Opportunity Service, which are provided as an opportunity service only when sufficient capacity exists on the transmission system to accommodate the scheduled capacity.138 Simply put there are no transmission rights in Alberta, whether they are rights for physical facilities (for intertie developers) or for commercial traders (for importers and exporters).

171. As noted by parties in this proceeding jurisdictions throughout North America, including BC, Quebec, and several US ISOs have various forms of transmission capacity markets. The Commission considers that transmission capacity markets, whether for the owners of physical facilities or for commercial traders, do not exist in Alberta and access to the AIES for importers and exporters is not provided on a firm basis. Without transmission rights in Alberta the Commission considers the existing practices elsewhere based on the existence of transmission rights are not instructive.

172. Regarding the hold harmless principle as argued by parties, the Commission considers there is a distinction between the rights for owners of physical facilities and for commercial traders. The potential requirement for a RAS scheme on a new intertie connecting to Alberta addresses the aspects of the hold harmless principle for physical facilities by ensuring a new intertie does not impair the reliability of the existing transmission system. As there are no transmission rights in Alberta, the commercial trading aspects of the hold harmless principle do not apply in Alberta since there are simply no transmission rights to protect.


5.1.5 Rule negatively impacts pool price

Impacts on pool price

174. Several parties conceded that during times of unconstrained interties the MATL intertie will result in increased imports into Alberta which, other things being unchanged, will result in decreased pool prices.139 MPOs argued that this consideration was irrelevant as the Proposed ATC Rule only comes into effect during times of constraint.140

175. Morgan Stanley submitted the Proposed ATC Rule will provide competition for the limited import space into Alberta and result in market discipline ensuring when there is a spread between Alberta and US markets that energy is able to flow. Over the course of 2010 and 2011 there were 2944 hours where there was a positive price difference of $10 /MWh or more between the hourly price in Alberta and the hourly price at Mid-Columbia (an electricity trading point in

138 The current AESO Tariff, effective July 1, 2011, as posted on the AESO website. 139 Exhibit 0146.01, NaturEner Evidence, June 15, 2012, pages 10-12. 140 Exhibit 0152.02, Coalition Rebuttal Evidence, July 20, 2012, pages 7-8.



southern Washington state) and at the same time the available transfer capacity to Alberta was not fully utilized. The Proposed ATC Rule facilitates market access for interties such as MATL, which will reduce hours when energy does not flow into Alberta when it should have.141 In addition, market participants who do not own firm transmission may access the unused capacity, however traders who do not have the predictability to flow energy across an intertie to access the Alberta market will not take the risk of not being able to flow energy.142

176. TransCanada submitted that under the Proposed ATC Rule the value of firm transmission service on the existing interties is reduced as holders face increased curtailments as a result of the new entrant MATL intertie, which will increase costs to holders of firm transmission service and may translate into higher prices in Alberta.143

177. The Coalition submitted that between T-85 and T-20 if any one of the AB-BC, MATL, or AB-SK interconnections is unable to supply up to its import ATC allocation for whatever reason, the Proposed ATC Rule would make up for the lost volume by dispatching up the supply curve rather than re-allocating this volume to the other intertie, which results in an increased pool price and is therefore inefficient.144

178. The Coalition submitted that the Proposed ATC Rule is likely to cause unnecessary pool price volatility as the RAS scheme on the MATL intertie may interrupt import transactions and, unlike on the AB-BC intertie, cause the AESO to dispatch up the merit order to maintain service to load.145

179. TransCanada submitted the increased risk to curtailments creates uncertainty and increases the risks associated with importing for firm transmission holders, which ultimately will increase the cost of importing and has the potential to reduce total imports and thus increase the Alberta pool price.146

Ancillary services

180. The Coalition submitted that the Proposed ATC Rule requires ancillary services transacted over the interconnections to be curtailed before energy transactions, which will have an impact on Alberta’s ancillary services market. As the interties have contributed between 20 and 25 per cent of the spinning reserves and a modest share of supplemental reserves to Alberta between 2007 and 2011, the Proposed ATC Rule will significantly impact the volume of reserves offered into the ancillary services market, and the lost ancillary services will need to be provided from a more expensive source which will increase the cost of ancillary services in Alberta.147

181. The AESO submitted that there is currently only one market participant who provides operating reserves across the AB-BC and AB-SK interties, and the ancillary services market restrictions limit the size of operating reserves per asset. Also, the AESO expects curtailments to

141 Exhibit 0144.02, MSCG Evidence, June 15, 2012, pages 24-25. 142 Exhibit 0280.02, Morgan Stanley Argument, October 29, 2012, pages 54-55. 143 Exhibit 0133.01, TransCanada Evidence, May 7, 2012, pages 21-22. 144 Exhibit 0129.01, Coalition Policy and Financial Impact Evidence, May 7, 2012, page 14. 145 Exhibit 0129.01, Coalition Policy and Financial Impact Evidence, May 7, 2012, page 23. 146 Exhibit 0133.01, TransCanada Evidence, May 7, 2012, pages 23-24. 147 Exhibit 0129.01, Coalition Policy and Financial Impact Evidence, May 7, 2012, page 14.



be relatively infrequent provided that adjacent transmission providers schedule within transfer limits as allocated at T-85 minutes.148

Additional transfers due to the energization of MATL

182. The Coalition submitted that the MATL interconnection can permit additional transfers of energy to the benefit of Alberta in two circumstances: when the BC Hydro system has an outage, and when market price differentials between jurisdictions render flows economic. Since 2003 roughly ten per cent of the hourly constraints on the AB-BC interconnection have been caused by restrictions in BC, which are hours when Alberta would be able to accept energy beyond what the AB-BC interconnection could deliver, however these circumstances are infrequent and impact on future price is anticipated to be minimal. Also, during six per cent of the hours in 2011 imports into Alberta would have increased as a result of imports over MATL being economic while imports over the AB-BC interconnection were not economic. However, the gross price spreads are relatively small at approximately $4/MWh for imports and exports, without including delivery costs, risk premiums and profit margins.149

183. Similarly TransCanada submitted that when the full import capability limit created by the AB-BC intertie is not fully used by market participants scheduling imports through BC, then imports could be scheduled over the MATL intertie which would reduce Alberta prices and thereby benefit Albertans.150

Commission findings

Impacts on pool price

184. The Commission considers that during times of constraint the Alberta pool price is unaffected by which intertie supplies energy to the AIES. However, the Commission accepts that there were hours when there were price spreads between Alberta and US markets but the AB-BC intertie was not used full capacity. The Commission considers competition should be most effective when there are more competing traders to discipline each other, whether during times of constraint or not.

185. Regarding impacts to firm transmission rights holders in neighbouring jurisdictions, the Commission has previously determined in this decision that these impacts are a competitive market response when there is a new entrant. Currently there is no ability for pricing imports and exports other than $0/MWh and $999.99/MWh respectively; and as such the Commission considers this impact to firm transmission rights holders in other jurisdictions is likely to have little, if any, impact on pool price in Alberta.

186. The Commission has previously determined in this decision that given the complexity of scheduling intertie transactions and the potential short timeframe to do so the Commission concludes that any resulting stranded capacity discovered between T-85 and T-20 will be infrequent and is one of the risks of operating interties in an electricity market two hours prior to the start of a settlement interval.

148 Exhibit 0145.02, AESO Evidence, June 20, 2012, page 23. 149 Exhibit 0129.01, Coalition Policy and Financial Impact Evidence, May 7, 2012, page 9. 150 Exhibit 0138.01, TransCanada (Roach) Evidence, May 7, 2012, pages 7-8.



187. The Commission was not presented with evidence of establishing expected pool price volatility under the Proposed ATC Rule. Several parties, including MPOs, submitted that the MATL intertie will provide additional imports into Alberta under various conditions and when there are no constraints on the interties.151 The Commission concludes that increased imports will, other things being equal, lead to greater competition to supply power in Alberta. Enbridge/MATL submitted the MATL intertie would not have been built if it weren’t for the ATC allocation method in the Proposed ATC Rule,152 and the Commission considers the prospect of greater competition to supply power to Alberta during non-constrained hours outweighs the potential for Alberta pool price volatility if or when the MATL intertie flows are interrupted by a RAS scheme.

188. Based on the evidence in this proceeding, including the pending requests from Cargill to BC Hydro for firm transmission service153 and the potential for the MATL intertie expansion, the Commission considers there are enough market participants that want to access the Alberta market that it is unlikely that imports into Alberta will decrease under the Proposed ATC Rule.

Ancillary services

189. Regarding ancillary services, the Commission accepts that the AESO system controller would require some flexibility when determining which operating reserves transactions should be applicable under various system conditions, and that the Proposed ATC Rule provides the system controller with the needed flexibility. The Commission is persuaded that the impact on pool price from such decisions by the system controller are likely to be minimized as curtailments are expected to be infrequent if adjacent transmission providers schedule within transfer limits as allocated at T-85 minutes.

Additional transfers due to the energization of MATL

190. The Commission accepts that the MATL intertie can permit additional transfers of energy when the BC electric system has an outage and during times of certain market price differentials, resulting in increased imports into Alberta via the MATL intertie. Enbridge/MATL submitted and the Commission concludes that if MATL was required to bring incremental ATC the MATL intertie may not have been constructed. The Commission accepts that the Proposed ATC Rule encouraged the construction of MATL, which will contribute to more competitive Alberta pool prices.


5.1.6 Rule leads to increased bookout fees

192. Several parties in this proceeding submitted that the Proposed ATC Rule will increase curtailments to transmission holders in other jurisdictions, resulting in higher occurrences of


Coalition Rebuttal Evidence, July 20, 2012, pages 7-8; Exhibit 0146.01, NaturEner Evidence, June 15, 2012, pages 10-12; Exhibit 0144.02, MSCG Evidence, June 15, 2012, pages 24-25.

152 Transcript Volume 6, September 18, 2012, page 1331; Exhibit 0283.02, Enbridge/MATL Argument, October 29, 2012, pages 32-34.

153 Exhibit 0129.01, Coalition Policy and Financial Impact Evidence, May 7, 2012, page 18.



bookout fees154 and higher transaction costs, which is economically inefficient and will lead to increased pool price in Alberta.155

193. TransCanada submitted the Proposed ATC Rule will lead to economically inefficient outcomes because the immediate cost of bookout fees could deter competition to import power into Alberta, resulting in the need for greater price differences between markets to incent exchanges that otherwise may have occurred. Further, in the long-term these increased fees could result in the termination of commercial relationships between Alberta market participants and suppliers in other jurisdictions.156

194. The Coalition and TransCanada submitted that to avoid bookout fees a firm transmission customer must receive knowledge of the amount of its allocation of transmission in sufficient time to procure the corresponding volume of energy. The Coalition submitted that under the Proposed ATC Rule the holders of firm transmission on the AB-BC intertie will not know their individual share of transmission until BC Hydro performs its curtailments at T-20, by which time it is too late to avoid bookout fees.157

195. Morgan Stanley submitted that PowerEx, as the largest holder of transmission rights on the AB-BC intertie with 78 per cent of firm and conditional firm transmission rights, does not incur bookout fees because it has access to the generation supply of BC Hydro, and so it does not have to unwind transactions with un-affiliated counterparties. Also, the T-2 and T-85 timing in the Proposed ATC Rule was adopted to be consistent with the timing of neighbouring and interconnected transmission and power markets, including Mid-C, and that with the knowledge at T-85 of the allocation to each intertie market participants will have ample time to source supply.158

196. The AESO and Morgan Stanley submitted the T-85 allocation provision in the Proposed ATC Rule provides greater certainty to shippers earlier in the allocation process.159

Commission findings

197. The Commission accepts that the AESO must provide sufficient time for the system controllers to operate the transmission system, and therefore must set cutoff times for submissions of offers and bids as well communicate with intertie operators and intertie shippers, among other tasks.

198. OPP 304: Alberta-BC Interconnection Transfer Limits is currently in effect. As part of its application for the Proposed ATC Rule the AESO proposes to remove this OPP. It states in Section 5.1 that in determining export transfer limits, prior to T-70 the system controller must

154 Bookout fees are costs that market participants pay on a per MWh basis for volumes of electric energy that does

not flow according to a pre-negotiated agreement between two counterparties. 155 Exhibit 0129.01, Coalition Policy and Financial Evidence, May 7, 2012, pages 12-13; Exhibit 0273.01,

NorthPoint Argument, October 15, 2012, page 18; Exhibit 0133.01, TransCanada Evidence, May 7, 2012, pages 23-25.

156 Exhibit 0272.03, TransCanada Evidence, October 15, 2012, pages 38-39. 157 Exhibit 0152.02, Coalition Rebuttal Evidence, July 20, 2012, page 13-14; Exhibit 0272.03, TransCanada

Evidence, October 15, 2012, pages 38-39. 158 Exhibit 0144.02, Morgan Stanley Evidence, June 15, 2012, pages 23-24. 159 Exhibit 0145.02, AESO Evidence, June 15, 2012, pages 18-19; Exhibit 0280.02, Morgan Stanley Argument,

October 29, 2012, pages 53-54.



determine various limits including ATC for the AB-BC intertie. Similarly, Section 5.2 of OPP 304 outlines the steps for import transfer limits without specifying a time limit.

199. Section 10(3) of the Proposed ATC Rule states that at T-85160 the ISO must post on its website the total MW of all import offers and export bids received by T-120 for each transfer path, the limits for each transfer path as referenced under Section 2 of the Proposed ATC Rule, and the allocations made to each transfer path as referenced under Section 10 of the Proposed ATC Rule.

200. The Proposed ATC Rule then states in Section 6(2) that the ISO must receive e-tags no later than T-20 in order for the energy components of the interchange transactions to be included in an interchange schedule referenced in Section 8 of the Proposed ATC Rule.

201. The Commission recognizes that the Proposed ATC Rule increases the time between when ATC limits are available and when e-tags have to be submitted. While the Commission recognizes that the allocation performed by the AESO at T-85 is at the intertie level, not the shipper level, and it is the responsibility of BC Hydro and MATL to reduce scheduled energy deliveries based on their respective curtailment priorities, the Commission is not convinced that there will be a material impact due to the potential increase to bookout fees. The Commission concludes that market participants will have sufficient time between T-85 and T-20 to make their final adjustments to procure energy and transmission capacity in other jurisdictions and submit e-tags for Alberta.

5.1.7 Rule impacts parties with firm transmission rights in other jurisdictions

202. Several parties in this proceeding indicated that the Proposed ATC Rule would degrade both existing and potential firm transmission rights in neighbouring jurisdictions and beyond,161 and some parties provided estimated financial impacts (including reduced firm energy transactions and bookout fees) on firm transmission holders in the neighbouring jurisdictions.162 TransCanada submitted that the AESO and Enbridge/MATL are in a position to mitigate the impacts of MATL intertie on the AB-BC intertie while BC Hydro and its customers who purchased firm transmission rights on it are not in a position to mitigate such risks.163

203. NorthPoint submitted that when it purchased firm transmission rights in BC that the interties received the ATC they provided to the system, and that PowerEx did not consider the effect of additional ties.164

204. The Coalition submitted the Proposed ATC Rule is unfair because it transfers, without compensation, ATC created by existing rate payer funded interconnection and paid for on

160 Throughout this proceeding parties used various methods to reference the time periods immediately leading into

a settlement interval. The Commission will refer to these time periods in a consistent manner as T-20, read as “T minus twenty”, to indicate 20 minutes prior to the start of the settlement interval, or T-120 to indicate one hundred twenty minutes prior to the start of the settlement interval.

161 Exhibit 0050.00, PowerEx Objection, December 19, 2011, page 6; Exhibit 0129.01, Coalition Policy and Financial Impact Evidence, May 7, 2012, pages 16-18; Exhibit 0133.01, TransCanada Evidence, May 7, 2012, pages 30-32; Exhibit 0138.01, TransCanada (Roach) Evidence, May 7, 2012, pages 5-6.

162 Exhibit 0129.01, Coalition Policy and Financial Impact Evidence, May 7, 2012, page 17; Exhibit 0133.01, TransCanada Evidence, May 7, 2012, pages 30-31.

163 Exhibit 0133.01, TransCanada Evidence, May 7, 2012, pages 31-32. 164 Transcript Volume 1, pages 42-43.



interconnected systems by the firm service rights holders on those systems to the merchant MATL line.165

205. Enbridge/MATL submitted that the value of firm transmission rights on the BC system is not relevant as the customers in BC did not pay for any rights to deliver into or through Alberta.166 In addition, Enbridge/MATL submitted that MATL intertie users are in the same position as the users of the AB-BC and AB-SK interties in that they have to hold firm transmission rights up to the MATL intertie’s point of connection with the AIES where they have injection/withdrawal rights that entitle them to a reasonable opportunity to exchange energy.167

206. Enbridge/MATL submitted that allocating ATC to the interties and having the intertie operator reallocate that ATC among its users in accordance with the OATT in the adjoining jurisdiction is a practical efficiency, and respects the rules of adjoining jurisdictions.168

207. The AESO submitted that rights purchased and effective in a jurisdiction outside of Alberta are not relevant, Alberta has never sold rights similar to those in BC, and has not made any representation that rights purchased in external jurisdictions have any value or weight in determining Alberta system access. Further, it is not common practice within the industry to enforce or impose rights purchased in external jurisdictions when allocating transmission capability within another jurisdiction.169 The AESO does not recognize transmission rights sold in other jurisdictions as providing any implicit or explicit priority access to the Alberta market.170

Commission findings

208. The BCUC decision limited the amount of firm or conditional firm transmission on the AB-BC intertie that could be sold by BCTC (now BC Hydro) to the amount of energy that could reasonably be delivered to Alberta. The Commission anticipates this practice will continue to apply. However, the Commission considers that the amount or volume of firm transmission rights sold in neighbouring jurisdictions is a matter to be dealt with appropriately in those jurisdictions.

209. Regardless of their rights in neighbouring jurisdictions, market participants who transmit electric energy over interties pay IOS or XOS tariff rates in Alberta. The Commission recognizes that interties, to the extent they are part of the AIES, are paid for by load in Alberta through the AESO tariff, with the exception of the MATL intertie which is privately funded. As such, the interties are not paid for by importers. Previously in this decision the Commission concluded that ATC should be treated as a system resource, and the Commission does not consider the allocation of ATC to the merchant MATL intertie under the Proposed ATC Rule to be unfair.

210. The Proposed ATC Rule may have an impact on the holders of firm transmission rights held in neighbouring jurisdictions, but the Commission does not find such impacts to be unfair or anti-competitive.

165 Exhibit 0129.01, Coalition Policy and Financial Impact Evidence, May 7, 2012, page 20. 166 Exhibit 0150.02, Enbridge/MATL (Craig Baker) Evidence, June 15, 2012, page 13. 167 Exhibit 0147.02, Enbridge/MATL Evidence, June 15, 2012, page 9. 168 Exhibit 0283.02, Enbridge/MATL Argument, October 29, 2012, page 6. 169 Exhibit 0145.02, AESO Evidence, June 15, 2012, pages 14-15. 170 Exhibit 0281.02, AESO Argument, October 29, 2012, pages 18-19.




5.1.8 Rule was not finalized when an investment decision was made

212. PowerEx submitted that Enbridge/MATL and Morgan Stanley might suggest that either the public interest standard or the fairness aspects of FEOC require the Commission to consider the investment decision of Enbridge/MATL initially and Morgan Stanley ultimately in assessing the Proposed ATC Rule. PowerEx submitted that Enbridge/MATL and Morgan Stanley knew the risks they were taking with respect to the development of the rule and the outcome of this proceeding when they made their investment, and that their investment decision should not play a part in the Commission’s assessment of the Proposed ATC Rule.171

Commission finding

213. The Commission agrees with PowerEx that Enbridge/MATL, NaturEner and Morgan Stanley made investment decisions prior to a finalized ISO rule regarding ATC allocation, and as sophisticated market participants they should have been aware of the potential risks associated with the final ATC allocation rule taking some kind of different form than the Proposed ATC Rule. In considering the objections in this proceeding the Commission has not given any weight to the investment decision made by Enbridge/MATL and Morgan Stanley while the Proposed ATC Rule was being developed.

5.1.9 Summary of Commission findings - FEOC

214. In summary, the Commission is not persuaded by any of the grounds raised by the MPOs that the Proposed ATC Rule does not support the FEOC operation of the market.

5.2 Rule is not in the public interest

215. Parties submitted that the Proposed ATC Rule is not in the public interest because the Proposed ATC Rule:

(a) Contravenes Section 16 of the Transmission Regulation;

(b) Contravenes Section 27 of the Transmission Regulation;

(c) Does not honour previous commitments for the connection of MATL; and

(d) Creates or aggravates seams issues between jurisdictions.

5.2.1 Transmission Regulation Section 16 and allocation of availability transfer capability


Restoring interties existing on August 12, 2004 to their path rating

16(1) In making rules under section 20 of the Act, and in exercising its duties under section 17 of the Act, the ISO must prepare a plan and make

171 Exhibit 0271.01, PowerEx Final Argument, October 15, 2012, page 34.



arrangements to restore each intertie that existed on August 12, 2004 to, or near to, its path rating.

(2) The plan to restore interties to their path ratings must specify how the ISO intends to restore and maintain each intertie to, or near to, its path rating without the mandatory operation of generating units.

(3) The plan to restore and maintain interties must be incorporated into and form part of the transmission system plan as soon as practicable.

(4) This section shall not be interpreted as meaning that priority should be given to interties that existed on August 12, 2004 over interties existing after that date in respect of the allocation of available transfer capability.

Obligation to restore interties up to their path ratings

217. Several parties submitted that the AESO’s obligation to restore interties is limited to those that existed on August 12, 2004, as set out in Section 16 of the Transmission Regulation, and the AESO does not have an obligation to restore new intertie projects to their path ratings.172

218. The AESO submitted that its obligation to restore interties that existed on August 12, 2004 to their path ratings is connected to its obligation to plan an unconstrained transmission system. The AESO does not view its obligation to mean that the AESO must plan to upgrade MATL to its path rating; rather the AESO is committed to addressing the Alberta system operating limit.173

Section 16(4) of the Transmission Regulation

219. Several parties submitted that Section 16(4) of the Transmission Regulation avoids any suggestion that ATC that might otherwise be allocated to new interties should be mandatorily allocated to existing interties, and that Section 16 does not provide the AESO with any guidance as to how it should allocate ATC, leaving the AESO flexibility when allocating ATC.174 TransCanada submitted Section 16(4) clarifies that the AESO cannot grant AIC resulting from a new intertie to an existing intertie as a means of restoring the existing interties to their path ratings.175 The UCA submitted that the rules of statutory interpretation guide the use of the words “shall not be interpreted as” and “should” is deliberate, and if the intent of Section 16(4) had been to prohibit a priority allocation, the words would have been more restrictive.176

220. Enbridge/MATL and Morgan Stanley submitted that Section 16(4) of the Transmission Regulation expressly contemplates that ATC will be allocated between new and existing interties and that such allocation should not provide existing interties with priority to ATC.177 Enbridge/MATL submitted that Section 16(4) of the Transmission Regulation is an interpretive 172 Exhibit 0142.02, ATCO Power Evidence, May 7, 2012, Appendix 2, page 1; Exhibit 0129.01, Coalition Policy

and Financial Impact Evidence, May 7, 2012, pages 20-21. 173 Exhibit 0281.02, AESO Argument, October 29, 2012, pages 12-13. 174 Exhibit 0271.01, PowerEx Argument, October 15, 2012, pages 5-6. 175 Exhibit 0272.03, TransCanada Evidence, October 15, 2012, pages 22-24. 176 Exhibit 0275.01, UCA Argument, October 15, 2012, page 13. 177 Exhibit 0147.02, Enbridge/MATL Evidence, June 15, 2012, page 9; Exhibit 0283.02, Enbridge/MATL

Argument, October 29, 20122, pages 23-24; Exhibit 0144.02, MSCG Evidence, June 15, 2012, pages 6-7; Exhibit 0144.02, MSCG Evidence, June 15, 2012, page 15.



clause, and that the phrase “shall not be interpreted” is mandatory. Further, Enbridge/MATL submitted the legislature did not need to provide a more broad based prohibition because such a prohibition is already entrenched in the Electric Utilities Act, and an interpretation of Section 16(4) of the Transmission Regulation that permits priority allocation conflicts with the framework set out in the Electric Utilities Act.178 Morgan Stanley submitted that the Electric Utilities Act establishes an energy-only market and to interpret Section 16(4) of the Transmission Regulation to grant priority in ATC is to grant a de facto right in transmission capacity in the Alberta market to legacy interties, which is in conflict with its parent legislation.179

Diminished ATC on existing interties

221. Several parties submitted that the Proposed ATC Rule diminishes ATC on the existing interties, that is not consistent with the requirements in Section 16 of the Transmission Regulation, and it increases the amount of capacity that the AESO will be required to acquire to restore the existing interties to their path rating.180

222. The Coalition submitted that it took the AESO approximately 20 months from the time it solicited stakeholder feedback on the October 2010 Intertie Restoration Recommendation Paper to the time it released its July 2012 Intertie Restoration: Response to Recommendation Paper Stakeholder Comments and Next Steps paper, and that it appears unlikely there will be an established plan to address transmission constraints anytime soon.181

223. TransCanada submitted the approach under the Proposed ATC Rule is inconsistent with the modern approach to statutory interpretation. It includes the presumption of coherence and Section 16(4) should not be read so as to defeat the original purpose and effect of Section 16(1).182

Commission findings

Obligation to restore interties up to their path ratings

224. The Commission considers sections 16(1) through (3) of the Transmission Regulation obligates the AESO to plan and make arrangements to restore each intertie that existed on August 12, 2004 to, or near to, its path rating without the mandatory operation of generating units, and that this plan must be incorporated into and form part of the transmission system plan as soon as practicable. The Commission finds that Section 16(1), (2) or (3), does not apply to future interties and does not obligate the AESO to plan to enable MATL, or any future interties, to transfer up to its path rating.

178 Exhibit 0283.02, Enbridge/MATL Argument, October 29, 20122, pages 23-24; Exhibit 0283.02,

Enbridge/MATL Argument, October 29, 20122, page 42. 179 Exhibit 0280.02, Morgan Stanley Argument, October 29, 2012, pages 11-12. 180 Exhibit 0050.00, PowerEx Objection, December 19, 2011, page 7; Exhibit 0055.00, NorthPoint Objection,

December 19, 2011, page 3; Exhibit 0129.01, Coalition Policy and Financial Impact Evidence, May 7, 2012, pages 20-21; Exhibit 0273.01, NorthPoint Argument, October 15, 2012, page 10.

181 Exhibit 0152.02, Coalition Rebuttal Evidence, July 20, 2012, pages 20. 182 Exhibit 0272.03, TransCanada Evidence, October 15, 2012, pages 22-24.



Section 16(4) of the Transmission Regulation

225. Section 16(4) of the Transmission Regulation must be read in the context of the scheme and the object of the Electric Utilities Act. The modern principle of statutory interpretation, described previously in this decision, was also identified by parties in this proceeding.183 Previously in this decision the Commission has provided its interpretation of electric system access rights under Alberta law.

226. The Commission interprets Section 16(4) as preventing sections 16(1) through (3) being taken as the basis for giving the interties existing on August 12, 2004 priority in respect of ATC allocation. The section does not prohibit the giving of such priority to these interties for other reasons which might readily have been expressed had such been the legislative intent. The section is silent about the outcome of such issue. The Commission concludes that the issue of such priority is left to be decided elsewhere in this decision for other reasons independent of Section 16 of the Transmission Regulation.

227. The Commission is not persuaded that the Proposed ATC Rule is not in the public interest on this basis.

Diminished ATC on existing interties

228. The Commission interprets Section 16 to leave the AESO with the discretion, under sections 16(2) and (3), on the form and timing of intertie restoration methods. Wholly consistent with the overarching scheme and context of the Electric Utilities Act regarding system access service and the requirement in Section 16(4) that the AESO not grant priority to existing interties when allocating ATC, the Commission considers the AESO is required to allocate ATC on a non-priority basis between interties. In certain circumstances this allocation may diminish ATC on the existing interties, but the AESO is in no way relieved of its legislated obligation to eventually restore those existing interties as set out in Section 16(1).

229. The Commission is not persuaded that by diminishing the ATC on the existing interties that the Proposed ATC Rule is not in the public interest.

5.2.2 Transmission Regulation Section 27 and cost responsibilities of merchant interties


Intertie projects

27(1) This section applies to the following:

(a) an intertie proposed to be constructed;

(b) an upgrade or enhancement to an intertie that proposes, or would result in, an increase to the path rating of the intertie.

183 ATCO Power in Exhibit 0277.02, ATCO Power Argument, October 15, 2012, page 9; NorthPoint in Exhibit

0273.01, NorthPoint Argument, October 15, 2012, pages 7-8; PowerEx in Exhibit 0271.01, PowerEx Argument, October 15, 2012, pages 7-8; Morgan Stanley in Exhibit 0280.02, Morgan Stanley Argument, October 29, 2012, pages 4-6.



(2) When the ISO prepares a needs identification document under section 34(1) of the Act for an intertie described in subsection (1), the needs identification document must

(a) contain the information required by section 11(3), unless the ISO determines that any of those matters are not required,

(b) describe the extent to which the ISO will make use of the proposed intertie to provide system access service,

(c) contain proposed agreements, arrangements, rates and terms and conditions for the ISO’s use of the intertie, and

(d) contain any other information that the ISO considers necessary in view of the nature of the proposed intertie.

(3) A person proposing an intertie to which this section applies must assist the ISO in preparing the needs identification document.

(4) The cost of planning, designing, constructing, operating and interconnecting an intertie to which this section applies must be paid by

(a) the person proposing the intertie, and

(b) other persons to the extent that they directly benefit from the intertie, based on the use described in the needs identification document approved by the Commission, and then only to the extent permitted by the ISO tariff.

(5) A person proposing an intertie to which this section applies, in accordance with the ISO rules, must

(a) provide open access to market participants by auction or other transparent process, and file the terms and conditions respecting open access with the Commission for information, and

(b) provide that the intertie be available in an open and non-discriminatory manner, similar to the access available to other transmission facilities.

(6) The ISO must include in the ISO tariff, rates and terms and conditions that include costs for use of the interconnected electric system, appropriate for the class of service provided to persons who use the intertie referred to in this section for import or export of electricity to or from Alberta.

Costs associated with building an intertie

231. Several parties in this proceeding submitted that the Proposed ATC Rule assigns rate-payer funded ATC from the AB-BC intertie to the merchant MATL intertie, and that this contravenes Section 27 of the Transmission Regulation which requires that intertie developers pay the costs associated with their interties.184

184 Exhibit 0055.00, NorthPoint Objection, December 19, 2011, pages 3-4; Exhibit 0273.01, NorthPoint Argument,

October 15, 2012, page 10; Exhibit 0274.01, SaskPower Argument, October 15, 2021, page 5.



232. The Coalition submitted that both provincial policy and regulatory precedent confirm that load is to bear the cost of facilities and operational measures on the interties themselves as well as any reinforcements within Alberta.185

233. NorthPoint submitted that the AESO lacks jurisdiction to make a rule under Section 20 of the Electric Utilities Act that transfers ratepayer funded ATC to a merchant intertie that is unregulated and not under the jurisdiction of the Commission or the AESO, and that such power could only rest with the Commission exercising its jurisdiction under Part 9, Division 2 of the Electric Utilities Act which provides the Commission with ratemaking authority.186

234. Morgan Stanley submitted that Section 27 is clear that the costs to be borne by the intertie developer are to be determined at the time the needs identification document is approved by the Commission. The needs identification document for MATL was approved by the EUB on January 31, 2008. Morgan Stanley submitted it would be unfair and inappropriate to now seek to attribute an AIES system cost for the creation of ATC to MATL on the basis that the cost falls under Section 27(4) of the Transmission Regulation.187 In addition, Morgan Stanley submitted that the cost of planning, designing, constructing, operating and interconnecting an intertie for the purposes of Section 27(4) of the Transmission Regulation should not include the creation of ATC because this treats existing and new interties differently by giving ATC priority to existing interties contrary to Section 16 of the Transmission Regulation.188

235. The AESO submitted that enabling merchant investment, whether in generating or transmission facilities, is in the public interest as minimal ratepayer costs are incurred to expand sources of potential power supply and increase competition.189

Costs associated with restoring existing interties

236. Several parties in this proceeding submitted that the Proposed ATC Rule, in conjunction with the AESO’s legislated obligation to restore existing interties to their path rating, will require Alberta ratepayers to pay the cost of replacing ATC that is transferred from the AB-BC intertie to MATL, and that this cost is imposed on them without a prudency review by the Commission.190

237. TransCanada submitted that the Proposed ATC Rule fails to differentiate between ATC that is enabled by LSSi and ATC that is not. This results in a subsidy from Alberta rate payers to the MATL intertie and requires the AESO to procure more LSSi or other products to offset the impacts of the Proposed ATC Rule on existing interties.191

185 Exhibit 0129.01, Coalition Policy and Financial Impact Evidence, May 7, 2012, pages 20-21. 186 Exhibit 0273.01, NorthPoint Argument, October 15, 2012, page 14. 187 Exhibit 0280.02, Morgan Stanley Argument, October 29, 2012, pages 7-8. 188 Exhibit 0280.02, Morgan Stanley Argument, October 29, 2012, page 9. 189 Exhibit 0281.02, AESO Argument, October 29, 2012, page 23. 190 Exhibit 0129.01, Coalition Policy and Financial Impact Evidence, May 7, 2012, page 21; Exhibit 0273.01,

NorthPoint Argument, October 15, 2012, page 13; Exhibit 0133.01, TransCanada Evidence, May 7, 2012, page 29; Exhibit 0137.02, Utilities Consumer Advocate Evidence, May 7, 2012, pages 5-6; Exhibit 0275.01, UCA Argument, October 15, 2012, pages 6-8;.

191 Exhibit 0133.01, TransCanada Evidence, May 7, 2012, pages 26-29; Exhibit 0138.01, TransCanada (Roach) Evidence, May 7, 2012, page 15; Exhibit 0272.03, TransCanada Argument, October 15, 2012, pages 22-24.



238. The AESO, in its October 2010 Intertie Restoration Recommendation Paper, considered that the cost of import and export restoration mechanisms, including LSSi, should be charged to load on the basis that these costs are akin to a non-wires solution.192

239. NaturEner submitted it would be inappropriate and inaccurate to characterize the costs for additional restoration efforts like LSSI as being on the account of the MATL intertie.193

Potential system costs for incremental ATC

240. Several parties in this proceeding submitted that the Proposed ATC Rule is premised on the proposition that the AESO is required to restore all interties up to their path ratings and that it is not in the public interest for the AESO to propose facility upgrades that are ratepayer funded or system costs associated with increasing the ATC on a merchant intertie.194

241. Capital Power expressed concern that load customers may be required to pay for any new DC converter stations associated with a merchant intertie, and submitted that there was insufficient evidence on the record to support any findings that such costs should fall to load and such a determination is outside the scope of this proceeding.195

242. Several parties submitted that the costs of system upgrades to build a system that provides for reasonable system access service are paid for by load, including VAR compensators for exports and LSSi service for imports.196 The AESO and Enbridge/MATL submitted that if the best way to increase import capability into Alberta was to build a converter station, the AESO would have to determine where the benefits lie and what portion of that would be a system versus customer cost, and then a need application would have to be brought before the Commission for approval.197

243. NaturEner submitted it remains open to BC Hydro to pursue an AC-DC-AC converter on its system and/or for the AESO to identify a need for one on either the MATL intertie or the AB-BC intertie.198

Commission findings

Costs associated with building an intertie

244. The Commission finds that there is no evidence persuading it that the costs described in Section 27(4) of the Transmission Regulation have not been paid by the operator of the MATL 192 AESO’s Intertie Restoration Recommendation Paper, October 7, 2010. Filed as Exhibit 0133.01, TransCanada

Evidence, May 7, 2012, Appendix E (tile 81 of the exhibit). 193 Exhibit 0282.01, NaturEner Argument, October 29, 2012, page 26. 194 Exhibit 0156.03, ATCO Power Rebuttal Evidence, July 20, 2012, page 8; Exhibit 0272.03, TransCanada

Argument, October 15, 2012, pages 11-12; Exhibit 272.03, TransCanada Argument, October 15, 2012, pages 25-26; Exhibit 0272.03, TransCanada Evidence, October 15, 2012, pages 39-40; Exhibit 0275.01, UCA Argument, October 15, 2012, pages 6-8..

195 Exhibit 0269.02, Capital Power Argument, October 15, 2012, pages 3-4. 196 Exhibit 0145.02, AESO Evidence, June 15, 2012, page 19; Exhibit 0147.03, Enbridge/MATL (Stout) Evidence,

June 15, 2012, pages 15-16; Exhibit 0283.02, Enbridge/MATL Argument, October 29, 2012, page 18; Exhibit 0283.02, Enbridge/MATL Argument, October 29, 20122, pages 40-41.

197 AESO witness at Transcript Volume 9, page 2010; Exhibit 0283.02, Enbridge/MATL Argument, October 29, 2012, page 19.

198 Exhibit 0282.01, NaturEner Argument, October 29, 2012, page 27.



intertie. The Commission does not interpret the types of cost impacts argued by the MPOs discussed under this heading as likely to result from future AESO requirements to make Alberta system enhancements to restore transfer capacity including fulfillment of the AESO’s obligation to restore ATC under Section 16 of the Transmission Regulation are costs to which Section 27 of the Transmission Regulation is applicable. Accordingly, these cost impacts of the Proposed ATC Rule do not constitute a breach of Section 27 of the Transmission Regulation, rendering the rule contrary to the public interest or otherwise constitute a valid ground for objection.


Costs associated with restoring existing interties

246. Previously in this decision the Commission has determined that ATC should be treated as a system resource which is enabled by interties rather than created by interties. LSSi facilitates an increase in ATC and is currently paid for by load customers in Alberta and treated as a system cost. The Commission considers that in order to meet the requirement of Section 16(4) of the Transmission Regulation of no priority access to ATC for existing interties, the Proposed ATC Rule should not distinguish between existing and new interties when allocating ATC that was enabled by LSSi.

247. The Commission is not persuaded that by not distinguishing between existing and new interties when allocating ATC enabled by LSSi the Proposed ATC Rule is not in the public interest.

248. ATCO Power introduced considerable evidence on the cost and effectiveness of the AESO’s LSSi initiative.199 This proceeding addresses the method for allocating ATC contained in the Proposed ATC Rule and whether it is technically deficient, does not support the FEOC operation of the market or is not in the public interest. The Commission considers the cost and effectiveness of the AESO’s LSSi initiative is not relevant to these issues and as such makes no determination regarding the AESO’s LSSi initiative.

Potential system costs for incremental ATC

249. This proceeding addresses the method for allocating ATC contained in the Proposed ATC Rule and whether it is technically deficient, does not support the FEOC operation of the market or is not in the public interest. The Commission considers the cost of potential facility upgrades or deep system costs are not relevant to this proceeding and as such makes no determination regarding such potential costs. Further, as noted by several parties, the Commission would expect these potential facilities would be brought before the Commission via the needs identification process, at which time a determination could be made regarding the appropriateness of the allocation of the costs for these potential facilities.

5.2.3 Previous commitments for connection of MATL

250. Several parties submitted that during the MATL facility application the AESO and Enbridge/MATL made commitments regarding the impact to existing interties, and that the

199 Exhibit 0139.04, ATCO Power Evidence, May 7, 2012, Appendix 3.



Proposed ATC Rule contravenes those commitments.200 The UCA submitted the original and approved approach to the effects of the MATL intertie on the AIES and ATC levels was to require MATL to implement technical or operational measures that would add ATC and not affect ATC provided by other interties.201

251. Morgan Stanley submitted that the National Energy Board (NEB) regulations are focused on technical and other reliability concerns and do not expressly consider economic impacts.202

252. Enbridge/MATL submitted that it has recognized its obligations to meet the WECC requirements by mitigating potential reliability impacts on the AIES and adjacent systems, but has never contemplated nor committed to protecting the incumbent users of the AB-BC intertie from the consequences of increased competition.203

253. Enbridge/MATL submitted that when the Alberta Energy and Utilities Board (AEUB) approved the need for MATL it did so with evidence before it, including the AESO’s need information documents, which anticipated the general characteristics of MATL, and any issues of design should have been raised at the time.204

254. The AESO submitted the commitments made in the initial MATL intertie proceeding were to ensure the operation of the MATL intertie would be undertaken in a safe and reliable way, such that existing users of the grid are not adversely impacted by the intertie. The AESO submitted that this is consistent with AEUB Decision 2008-006 approving the MATL need identification document and the NEB’s recent decision refusing to review and vary the issuance of its MATL permit.205

Commission findings

255. In Section 6 of AEUB Decision 2008-006, in relation to the NEB’s April 4, 2007, decision issuing Permit EP-301, approving the MATL intertie, the AEUB indicated “[t]he Board [AEUB] does not believe that it has the authority to overturn or revisit the findings of the NEB” including:

The Board (NEB) is of the view that the issue of potential impacts on the AIES is being considered by AESO and the EUB.

The Board (NEB) notes that due to the nature of the interconnection between Alberta and Saskatchewan, instability on the proposed IPL [MATL intertie] would not negatively impact power systems in the province of Saskatchewan. As well, the Board (NEB) is satisfied that once the WECC study is completed and appropriate mitigation measures

200 Exhibit 0129.01, Coalition Policy and Financial Impact Evidence, May 7, 2012, pages 2-3; Exhibit 0272.03,

TransCanada Argument, October 15, 2012, pages 37-38; Exhibit 0137.02, Utilities Consumer Advocate Evidence, May 7, 2012, page 7.

201 Exhibit 0137.02, Utilities Consumer Advocate Evidence, May 7, 2012, pages 9-10. 202 Exhibit 0144.02, MSCG Evidence, June 15, 2012, pages 15-16. 203 Exhibit 0147.02, Enbridge/MATL Evidence, June 15, 2012, pages 6-8. 204 Exhibit 0147.02, Enbridge/MATL Evidence, June 15, 2012, pages 2-3. 205 Exhibit 0145.02, AESO Evidence, June 15, 2012, pages 19-21.



and remedial action schemes are implemented, the proposed IPL [MATL intertie] would not negatively impact power systems in British Columbia.206

256. The Commission considers that the impacts to the AIES of the MATL intertie are being addressed by WECC and AESO system studies, and expects that the MATL intertie will be compliant with any RAS schemes identified in those studies as required for the safe and reliable operation of the AIES.

257. The Commission considers the NEB decision was clear regarding impacts to the BC and Saskatchewan systems, in that the NEB was satisfied that the WECC studies would identify the need for mitigation measures and remedial action schemes so that the MATL intertie would not negatively impact power systems in British Columbia. Further, the NEB stated in its Letter Decision that it was not persuaded there was a requirement on MATL to “…identify and mitigate outstanding concerns related to the reduction in transfer capability on other paths beyond those concerns identified through the WECC path rating process” and that the WECC path rating process “…is concerned with reliability concerns and not commercial matters.” Further, the NEB stated that “the requirements in condition 10 [being the 10th condition for the approval of the MATL facility as set out by the NEB] are consistent with subsections 6 (d) and (h) of the Regulations [National Energy Board Regulations], which define certain terms and conditions that may be included in any permit for an international power line in regards to, among others, the adverse effects on the reliability of any power systems to which the facilities are interconnected. The Board notes that these subsections are focused on technical and other reliability concerns and do not expressly consider economic impacts.”207


5.2.4 Seams issue between jurisdictions

259. PowerEx submitted that while the AESO can determine the allocation limits for each intertie, the neighbouring jurisdictions will deliver whatever energy they schedule up to their allocation limits, and that the AESO cannot determine which shippers actually receive ATC.208

260. TransCanada submitted the Proposed ATC Rule impedes the integration of the Alberta market into the North American electricity market as it fails to accommodate widely accepted practices, such as accommodating existing firm transmission customers, and that while FERC has no regulatory jurisdiction in Alberta it could take action only through reciprocity concerns.209

261. Enbridge/MATL submitted the potential of inter-jurisdictional seams is inherent in the architecture of the Alberta system and that the AESO’s role is to find trade-offs and practical

206 AEUB Decision 2008-006, issued January 31, 2008, page 11. 207 NEB File OF-Fac-IPL-M159-2005-01 06, British Columbia Hydro and Power Authority (BC Hydro) application

for relief regarding the Montana Alberta Tie Ltd. Permit EP-301 issued by the National Energy Board on 4 April 2007, dated February 16, 2012, page 7. In this proceeding there were several submissions relating to the possible impact of the NEB ruling on this proceeding, and on May 1, 2012, the Commission issued a process letter indicating it added the NEB decision to the record in this proceeding. It was assigned Exhibit 0127.01, filed on May 1, 2012.

208 Exhibit 0271.01, PowerEx Argument, October 15, 2012, page 16. 209 Exhibit 0138.01, TransCanada (Roach) Evidence, May 7, 2012, pages 9-11.



compromises on a system that must rank safety, supply security, and longer-term FEOC market goals above short-term trading outcomes.210

262. Enbridge/MATL submitted that FERC reciprocity concerns were in regard to transmission system owners that were not providing open system access and did not concern specific forms of transmission service or the treatment of transmission rights.211

263. NaturEner submitted that the allocation of ATC to the interties rather than directly to the shippers on them was one consistent message delivered by stakeholders which the AESO has incorporated into the Proposed ATC Rule, and that the Proposed ATC Rule reduces seams issues by allowing the intertie operators to carry out necessary curtailments in accordance with the commercial rights held on each intertie outside Alberta.212

264. The AESO submitted that its current practices recognize seams issue management by providing sufficient time to adjacent providers to conduct curtailments according to their tariff and the terms and conditions of transmission rights they have sold within their jurisdiction, and that the Proposed ATC Rule continues this practice by providing a capacity allocation amongst interties at T-85.213

Commission findings

265. There are always likely to be seams issues between jurisdictions that have different electricity market structures, such as between Alberta and British Columbia or Saskatchewan. As there are no transmission rights in Alberta, under the Proposed ATC Rule the AESO will determine the ATC over each intertie and at T-85 will post the offers and bids received over all interties and the ATC limits for each intertie on its website for all market participants to access. At T-85 BC Hydro and MATL, which are the operators responsible for scheduling shippers in accordance with their own curtailment priority, will have the information needed to allocate ATC to shippers on their own interties. Also at T-85 shippers on each intertie will be able to see the total import offers and export bids and will be able to reasonably determine their anticipated ATC allocation, and complete the necessary steps to arrange their e-tags.


5.2.5 Summary of Commission findings – public interest

267. In summary, the Commission is not persuaded by the grounds raised by the MPOs that the Proposed ATC Rule is not in the public interest.

5.3 Rule is technically deficient

268. Parties submitted that the Proposed ATC Rule is technically deficient because the Proposed ATC Rule:

(a) Prematurely incorporates a pricing mechanism;

210 Exhibit 0147.03, Enbridge/MATL (Stout) Evidence, June 15, 2012, page 7. 211 Exhibit 0150.02, Enbridge/MATL (Craig Baker) Evidence, June 15, 2012, pages 14-15. 212 Exhibit 0282.01, NaturEner Argument, October 29, 2012, page 17. 213 Exhibit 0145.02, AESO Evidence, June 15, 2012, page 15.



(b) Fails to adequately address allocation and curtailment of ancillary services;

(c) Fails to account for existing transmission commitments;

(d) Incorrectly allocates ATC created by LSSi;

(e) Is insufficiently transparent and is missing definitions;

(f) Uses incorrect values for calculation of pro-rata allocation

(g) Fails to re-allocate stranded capacity between T-85 and T-20; and

(h) Fails to contemplate future interties.

5.3.1 Rule prematurely incorporates a pricing mechanism

269. Several parties referred to the current lack of a mechanism for intertie transactions to set market price in Alberta and argued that the Proposed ATC Rule prematurely incorporates a mechanism for allocating ATC between interties based on the offer and bid prices of intertie transactions.214

270. The Coalition submitted it is not possible to determine the effect that this mechanism may have at this time, and that the inclusion of pricing is illusory and obscures the significance of the pro-rata allocation methodology.215

271. ATCO Power submitted that the Proposed ATC Rule cannot meet the AESO’s stated objective of curtailing based on energy price because actual flows are determined by whether transactions are firm in neighbouring jurisdictions. Depending on the scenario it could be the cheapest offers that are actually curtailed rather than the most expensive offers.216

272. Morgan Stanley submitted that it is through the operation of the pricing portion of the Proposed ATC Rule that the effect will be known, and that if at the time that a pricing mechanism is implemented a concern arises with the operation of the Proposed ATC Rule there are avenues available for such concerns to be considered and addressed under the Electric Utilities Act.217

273. NaturEner supported the AESO’s efforts to achieve pricing of power supplied on the interties and noted that it has been requested by market participants, including TransCanada and PowerEx, for some time.218

214 Exhibit 0142.02, ATCO Power Evidence, May 7, 2012, Appendix 1, pages 1-2; Exhibit 0277.02, ATCO Power

Argument, October 15, 2012, page 10; Exhibit 0156.03, ATCO Power Rebuttal Evidence, July 20, 2012, page 5; Exhibit 0129.01, Coalition Policy and Financial Impact Evidence, May 7, 2012, page 25; Exhibit 0055.00, NorthPoint Objection, December 19, 2011, page 5; Exhibit 0273.01, NorthPoint Argument, October 15, 2012, page 18; Exhibit 0272.03, TransCanada Argument, October 15, 2012, pages 48-49; Exhibit 0153.02, TransCanada Rebuttal Evidence, July 20, 2012, page 12.

215 Exhibit 0129.01, Coalition Policy and Financial Impact Evidence, May 7, 2012, page 25. 216 Exhibit 0277.02, ATCO Power Argument, October 15, 2012, page 10. 217 Exhibit 0280.02, Morgan Stanley Argument, October 29, 2012, page 22. 218 Exhibit 0282.01, NaturEner Argument, October 29, 2012, page 16.



274. The AESO submitted that merit order dispatch is central to the Alberta market design, and that it plans in 2013 to introduce the capability for intertie transactions to be dispatchable. Further, there is no detriment caused from including reverse merit order (RMO) in the allocation procedure at this time, and that signaling the future use of RMO now will enable a more efficient ISO rule and IT system development and provide clear direction to market participants including potential intertie developers.219

Commission findings

275. As indicated in the consultation record for Proposed ATC Rule the Commission recognizes that market participants have requested a mechanism to allow for shippers to price their bids and offers over the interties, and through inclusion of a pricing mechanism in the Proposed ATC Rule the AESO has signaled that such a mechanism may be imminent. However, the Commission must consider the Proposed ATC Rule in the context of the current conditions in which shippers on the interties are not able to control their bid and offer prices.

276. The Proposed ATC Rule provides that when transfer path limits are exceeded the first allocation is done based on bid and offer prices, as stated in Section 10(2)(c)(ii) of the rule, before moving to a pro-rata allocation in Section 10(2)(c)(iii).

277. ISO rules Section 201.5: Block Allocation, currently in effect in Alberta, indicates that the ISO will allocate “to each source asset that is an import, one (1) operating block for energy with a zero dollar ($0.00) offer price” and “to each sink asset that is an export, one (1) operating block for energy with a nine hundred and ninety-nine dollar and ninety-nine cent ($999.99) bid price.” It is clear that import and export transactions are assigned rather than choose a price, either $0 or $999.99, respectively.

278. While it is clear from ISO rule 3.5.1 that shippers are assigned their bid and offer prices, the Commission considers that imports and exports are still offered and bid at a price, and the inclusion of an allocation based on price simply reflects this process. Further, while the Proposed ATC Rule may in effect revert to a pro-rata methodology under the current market rules, the Commission recognizes that market participants in this proceeding clearly understand that shippers cannot control their bid or offer prices on the interties, and as such are aware that under the current ISO rules the Proposed ATC Rule will effectively skip allocation based on price and will default to pro rata allocation.

279. The Commission is not persuaded that the Proposed ATC Rule is technically deficient on this basis.

5.3.2 Rule fails to adequately address allocation and curtailment of ancillary services

280. Parties submitted that the Proposed ATC Rule fails to adequately address ancillary services curtailment as the Proposed ATC Rule does not include a mechanism to apportion any required ancillary service curtailments between interties or participants.220

219 Exhibit 0145.02, AESO Evidence, June 15, 2012, page 21. 220 Exhibit 0129.01, Coalition Policy and Financial Impact Evidence, May 7, 2012, page 26; Exhibit 0050.00,

PowerEx Objection, December 19, 2011, page 6.



281. The AESO and Morgan Stanley submitted that the Proposed ATC Rule clearly outlines ancillary service curtailment which will be performed prior to any energy transactions on the intertie and that the system controller will determine which operating reserves transactions are curtailed considering the reliability assessment made at the time.221

Commission findings

282. Section 10(2)(c)(i) of the Proposed ATC Rule, which is attached as an appendix to this decision, specifies that if the combined transfer path limit in Section 2(1)(b) is exceeded the BC, or the Montana, or both the BC and the Montana transfer path allocations must be reduced as necessary by the applicable ancillary services type interchange transaction amounts.

283. The Commission accepts that the AESO system controller would require some flexibility when determining which operating reserves transactions would be applicable under various system conditions, and that the Proposed ATC Rule needs to and does provide the system controller with this flexibility.


5.3.3 Rule fails to account for existing transmission commitments

285. TransCanada submitted that the Proposed ATC Rule ignores the existing users on the AB-BC intertie and thus the Proposed ATC Rule is technically deficient because it does not correctly calculate ATC, which by industry standards (as set out by NERC for all US utilities) includes deducting existing transmission commitment (ETC) from TTC to determine ATC.222 TransCanada indicated that the NERC glossary of terms included a definition for existing transmission commitments, which is “[c]ommitted uses of a Transmission Service Provider’s Transmission system considered when determining ATC or AFC.”223

286. Supporters of the Proposed ATC Rule argued that there are no transmission rights in Alberta, that firm transmission rights in neighbouring jurisdictions should not be recognized in Alberta, and as such there are no ETC’s in Alberta to consider when calculating the ATC for interties.224 Further, NaturEner submitted that if recognizing firm transmission commitments in a neighbouring system were recognized in the Proposed ATC Rule then it would also have to be recognized on the MATL intertie, not just the AB-BC intertie, in order to allow shippers on all interties equal opportunity to access the Alberta market.225

221 Exhibit 0145.02, AESO Evidence, June 20, 2012, page 23; Exhibit 0280.02, Morgan Stanley Argument, October

29, 2012, pages 22-23. 222 Exhibit 0138.01, TransCanada (Roach) Evidence, May 7, 2012, pages 8-9; Exhibit 0272.03, TransCanada

Argument, October 15, 2012, page 48. 223 Exhibit 0133.01, TransCanada Evidence, May 7, 2012, page 35. 224 Exhibit 0150.02, Enbridge/MATL (Craig Baker) Evidence, June 15, 2012, page 14; Exhibit 0280.02, Morgan

Stanley Argument, October 29, 2012, page 23; Exhibit 0282.01, NaturEner Argument, October 29, 2012, pages 13; Exhibit 0145.02, AESO Evidence, June 20, 2012, page 18; Exhibit 0281.02, AESO Argument, October 29, 2012, page 25.

225 Exhibit 0282.01, NaturEner Argument, October 29, 2012, pages 13.



Commission findings

287. In Alberta there are no transmission rights and transmission is allocated upon dispatch from the AESO. The NERC definition of ETC has not been adopted in Alberta. The Commission finds that no existing transmission commitments or committed uses of transmission outside of Alberta should be considered when calculating ATC on the Alberta transmission system. There is no ETC applicable in Alberta.


5.3.4 Rule incorrectly allocates ATC created by LSSi

289. TransCanada submitted that the Proposed ATC Rule does not include a mechanism for identifying Alberta interchange capability (AIC) created through the arming of LSSi and AIC that is not, treats all AIC in the same fashion, and fails to provide a mechanism to account for costs of LSSi that should be allocated to the owner of a merchant intertie as required under Section 27 of the Transmission Regulation.226

290. ATCO Power raised concerns regarding the effectiveness and cost allocation for the AESO’s LSSi program.227 The AESO responded that arguments regarding the cost efficiency of LSSi are beyond the scope of the issue in this proceeding, which is the merit of the Proposed ATC Rule.228

291. NaturEner submitted that under the applicable legislative framework the AESO is not permitted to allocate ATC in a manner that recognizes a priority access by granting ATC or capacity created through restoration initiatives to existing interties first.229

292. The AESO submitted that there is no distinction between ATC created by LSSi or by other methods, it cannot with any certainty identify who created ATC and it would be inappropriate to attempt to allocate ATC in different ways.230

Commission findings

293. The Commission considers that it does not need to decide the issues of the effectiveness and cost efficiency of LSSi to determine the merits of the Proposed ATC Rule and so it will not make any determinations regarding the effectiveness and costs of LSSi in this proceeding.

294. The AESO’s LSSi program increases ATC throughout the entire AIES, is one of the costs associated with operating the AIES, and is paid for by load customers in Alberta. While in the past the AB-BC intertie has enjoyed the benefits of increased imports due to the LSSi program, shippers on the AB-BC intertie have not paid the costs associated with LSSi. As LSSi is a program to increase ATC on the AIES, the Commission considers that shippers on the MATL intertie should have as much access to ATC enabled by LSSi as created in any other manner. 226 Exhibit 0272.03, TransCanada Argument, October 15, 2012, page 47. 227 Exhibit 0142.02, ATCO Power Evidence, May 7, 2012, pages 7-8 and Appendix 3. 228 Exhibit 0145.02, AESO Evidence, June 15, 2012, page 2. 229 Exhibit 0282.01, NaturEner Argument, October 29, 2012, pages 10-13. 230 Exhibit 0281.02, AESO Argument, October 29, 2012, page 25.




5.3.5 Rule is insufficiently transparent and is missing definitions

296. Parties argued that the Proposed ATC Rule lacked definitions for key terms used in the rule, and certain key information should be located in the Proposed ATC Rule and not in the Draft Information Document Available Transfer Capability and Transfer Path Management ID# 2011-001R (ID# 2011-001R).

297. NorthPoint submitted that several terms require clarification. NorthPoint submitted the AESO indicated that system studies will determine path ratings which will then be used to determine curtailments under the Proposed ATC Rule, and the Proposed ATC Rule provides examples of capability limits but there is no certainty about them as studies are ongoing and their completion cannot be reasonably predicted at this time. Further, “transfer path” is not a defined term and “available transfer capability” has a different meaning in ID# 2011-001R than in the ISO Consolidated Authoritative Documents Glossary. NorthPoint indicated that available transfer capability is defined in ID# 2011-001R, however in the new definitions available transfer capability includes reference to terms such as “commercially available”, “committed uses” and “existing transmission commitments”, none of which are defined terms. It is also unclear whether Section 2(1)(b) of the Proposed ATC Rule refers to available transfer capability of the combined British Columbia and Montana transfer paths or some other concept and whether the term “limit” in Section 2(2) refers to available transfer capability or some other limit.231

298. Several parties raised concerns that the mechanisms used to calculate various limits are not included in the Proposed ATC Rule but rather in the incomplete ID# 2011-001R that is not subject to regulatory oversight, and that these mechanisms and calculations are needed to assess the impact of the Proposed ATC Rule.232

299. TransCanada also raised a concern that the AESO has indicated it will follow the practices outlined in several Alberta reliability standards that have not yet been approved by the Commission as they have yet to be filed, which creates uncertainty for market participants.233

300. NaturEner submitted the mechanism for allocating ATC to interties under the Proposed ATC Rule clearly sets out the process steps that the AESO intends to follow to allocate ATC among interties when there is insufficient ATC to accommodate all shippers, and the fact that the amount of energy that can flow is variable does not mean that the Proposed ATC Rule is not clear.234

231 Exhibit 0055.00, NorthPoint Objection, December 19, 2011, page 5. 232 Exhibit 0055.00, NorthPoint Objection, December 19, 2011, page 5; Exhibit 0050.00, PowerEx Objection,

December 19, 2011, pages 5-6; Exhibit 0129.01, Coalition Policy and Financial Impact Evidence, May 7, 2012, page 25; Exhibit 0152.02, Coalition Rebuttal Evidence, July 20, 2012, page 14; Exhibit 0272.03, TransCanada Argument, October 15, 2012, page 47.

233 Exhibit 0272.03, TransCanada Argument, October 15, 2012, page 47. 234 Exhibit 0282.01, NaturEner Argument, October 29, 2012, page 14.



301. Morgan Stanley submitted that in AUC Decision 2009-007235 the Commission previously noted that the fact that an AESO rule is not completely self-contained is not in and of itself fatal, nor is it technically deficient. Also, the AESO has confirmed that the methodology for calculating import and export transfer limits will not change as a result of the Proposed ATC Rule, and upon completion of certain studies an information document will be published to accompany the Proposed ATC Rule.236

302. The AESO submitted that specific details regarding transfer limits under various system conditions can vary as the system configuration changes and are not appropriate content for a rule. Also, these transfer limits do not alter the underlying principles as to how the limits are calculated or allocated, or how curtailment is conducted. The AESO has committed to include specific details of transfer limits in an information document as they become available.237 The AESO submitted that despite the MPOs claims that the Proposed ATC Rule is unclear, the Proposed ATC Rule and draft information document provided enough detail for MPOs to produce their expected revenue impact due to the Proposed ATC Rule.238

Commission finding

303. Regarding the definition of “path rating”, the AESO has indicated that it is participating in the MATL WECC path rating and RAS design review process and conducting operational studies to determine individual intertie and system transfer limits such that the reliability of the grid is maintained.239 The Commission considers the term path rating is a common industry standard, the value of the MATL path rating will be determined by the WECC design review process and it does not need to be defined in the Proposed ATC Rule at this time.

304. Regarding the capability limits indicated in the Proposed ATC Rule, the Commission accepts that the AESO is conducting system studies and will publish the resulting capability limits in an information document.

305. The term “transfer path” is not defined in the Electric Utilities Act, Transmission Regulation or the AESO’s Consolidated Authoritative Documents Glossary. However, the term “intertie” is defined in the AESO’s Consolidated Authoritative Documents Glossary as having the same meaning as that provided in the Transmission Regulation, but the term intertie does not appear anywhere else in the AESO’s Consolidated Authoritative Documents Glossary nor does it appear in the Proposed ATC Rule. The Commission understands that Path 1 is defined in the AESO’s Consolidated Authoritative Documents Glossary as “the Alberta – British Columbia transfer path as identified by WECC in the document Major WECC Transfer Paths in the Bulk Electric System”, and that in the same document the term “qualified transfer path” is defined as “a transfer path designated by the WECC Operating Committee as being qualified for WECC unscheduled flow mitigation.” The Commission understands the term “transfer path” as defined

235 AUC Decision 2009-007: Objections to ISO Rule 6.3.5, 6.3.6 and Appendix 7, Long Lead Time Energy

Dispatches and Directives, January 19, 2009, page 10. 236 Exhibit 0280.02, Morgan Stanley Argument, October 29, 2012, page 22. 237 Exhibit 0145.02, AESO Evidence, June 15, 2012, pages 22-23. 238 Exhibit 0281.02, AESO Argument, October 29, 2012, page 24. 239 Exhibit 0145.02, AESO Evidence, June 15, 2012, pages 20-21.



by WECC240 encompasses the term intertie as defined in the Electric Utilities Act, unless otherwise stated in the ISO rules.

306. The term “available transfer capability” is defined in the AESO’s Consolidated Authoritative Documents Glossary. On December 5, 2011, the AESO filed an application to amend, among other things, the definition of available transfer capability, which was assigned Application No. 1607957 by the Commission. On December 6, 2011, the Commission published a notice of filing of ISO rules and notice for objection. No objections were received by the December 16, 2011 deadline, and the amendment to the definition of available transfer capability came into effect on January 31, 2012 as indicated in the AESO’s application. The Commission considers market participants were given sufficient notice of the proposed amendments to the definition of available transfer capability. The legislation provides market participants an opportunity under Section 25(1) of the Electric Utilities Act to complain about an ISO rule that is currently in effect; such would be the appropriate forum to hear NorthPoint’s concerns about this defined term.

307. Regarding the contents of information documents and pending reliability standards, Section 20(1)(c) of the Electric Utilities Act states the AESO may make rules respecting the operation of the interconnected electric system. As raised by Morgan Stanley the Commission has previously indicated it would prefer that any rules filed by the ISO are complete and reasonably self-contained; however, it recognizes that there may be occasions where the interaction between one rule or OPP or another rule or OPP does not allow for a complete set of rules and/or OPPs to be considered at a single point in time. Such circumstances are best dealt with on a case by case basis. In this case the Commission considers the information to be provided in the pending information document and reliability standards is not needed to understand the principles of how the Proposed ATC Rule will allocate ATC among the interties.


5.3.6 Rule uses incorrect values for the calculation of pro-rata allocation

309. MPOs in this proceeding indicated that the path rating should be used in determining the pro-rata allocation of ATC. While the MPOs did not clearly indicate the ground of this objection, namely whether it was a technical deficiency, did not support the FEOC operation of the market or was not in the public interest, the Commission will consider this issue here.

310. NorthPoint and the Coalition indicated it is unclear why MATL is assigned its path rating of 300 MW for the purpose of calculating allocations when the AESO indicated that path ratings are not used in ID# 2011-001R for the purpose of calculating allocations.241

311. BC Hydro argued that instead of using the volume of offers and bids to allocate ATC, the AESO should use the path rating of each intertie; this would reflect the full physical

240 http://www.wecc.biz/library/WECC%20Documents/Publications/WECC%20Glossary%2012-9-2011.pdf 241 Exhibit 0273.01, NorthPoint Argument, October 15, 2012, page 19; Exhibit 0129.01, Coalition Policy and

Financial Impact Evidence, May 7, 2012, page 26; Exhibit 0152.02, Coalition Rebuttal Evidence, July 20, 2012, pages 14-15.



capabilities of the respective interties to which it applies and reflect both the commercial and reliability value of each intertie.242

312. Enbridge/MATL submitted that whether the path rating of the AB-BC intertie is 1,200 MW or 12,000 MW does not change the ATC available on the Alberta system. Further, using path rating as an allocation methodology would allocate ATC to the AB-BC intertie that it cannot use to deliver into Alberta, even if all of the available ATC were allocated to the AB-BC intertie.243

313. Morgan Stanley submitted that BC Hydro is proposing to allocate ATC based primarily on path ratings in neighbouring jurisdictions without regard for Alberta system capabilities and limitations, even though the combined AB-BC and MATL transfer path ATC will be limited to a significantly lower capacity, and that any MW’s beyond the Alberta system capability have no chance of actually flowing. In support of this, Morgan Stanley cited a recent ruling by the BCUC. The decision indicated that the BCTC (now BC Hydro) cannot reasonably expect to be able to flow up to the WECC path rating of 1,200 MW and decided the capacity is not properly available if the energy cannot flow to its intended destination. The BCTC was prevented from selling more than a maximum of 785 MW of transmission access (consisting of 480 MW of firm and 305 MW of conditional firm transmission). Further, Morgan Stanley submitted that the Proposed ATC Rule has been constructed to accurately reflect the system realities present inside Alberta and in neighbouring jurisdictions.

Commission ruling

314. Section 3(1) of the Proposed ATC Rule states “[t]he ISO must determine the import total transfer capability and the export total transfer capability for an individual transfer path, in order to determine the import available transfer capability and the export available transfer capability for that transfer path.” Also, upon review of draft ID# 2011-001R it is clear to the Commission that where the AESO is using the path rating of MATL, it is doing so for illustrative purposes. For example, the title of Table 6 in ID# 2011-001R is Capability Limits Illustration [emphasis added]. As noted earlier in this decision the AESO’s Consolidated Authoritative Documents Glossary defines ATC. While under certain system conditions the ATC for MATL may reach its path rating, the Commission does not believe the AESO is allocating capacity to MATL based on its path rating as alleged by NorthPoint and the Coalition.

315. BC Hydro’s evidence indicates that in 2011 the ATC over the AB-BC intertie exceeded 600MW five per cent of the time and exceeded 500MW 50 per cent of the time, and since 2003 the constraints responsible for limiting this ATC have been sourced in Alberta approximately 90 per cent of the for import or export.244 While the WECC defined path rating of the AB-BC intertie is 1,200 MW for import purposes, based on the evidence the Commission considers it unrealistic to assume that 1,200 MW could currently be transmitted over the AB-BC intertie given the constraints in the Alberta system.

316. The Commission accepts the AESO’s use of the transfer capability to determine the pro-rata allocation because transfer capability reflects flows that are actually achievable over the

242 Exhibit 0270.02, BC Hydro Argument, October 15, 2012, page 15. 243 Exhibit 0283.02, Enbridge/MATL Argument, October 29, 2012, page 38. 244 Exhibit 0134.02, BC Hydro Evidence, May 7, 2012, page 4.



interties under the current system conditions in both Alberta and BC. The Commission does not consider that using the path rating to determine the pro-rata allocation would be realistic.


5.3.7 Rule fails to reallocate stranded capacity between T-85 and T-20

318. The Coalition submitted that if after T-85 the AESO became aware that a constraint on the AB-BC or MATL interties would limit flows on that intertie below its allocated quantity, there is no mechanism to re-allocate any stranded capacity to the other intertie prior to the start of the hour, which would cause the AESO to move up the merit order and dispatch enough generation to make up the stranded capacity. The Coalition argued that the Proposed ATC Rule should contain a provision for the re-allocation of capacity prior to T-20 should a constraint arise that would limit flows on either intertie.245

Commission findings

319. The Commission recognizes there is the potential for stranded capacity if a constraint develops on the AB-BC or MATL interties after T-85. However, scheduling intertie transactions is more complex than dispatching intra-Alberta generation as intertie transactions first require the AESO to communicate transfer capability to the neighbouring jurisdictions, the neighbouring jurisdictions must then determine which transmission customers to dispatch, the dispatched transmission customers must then arrange or confirm generation, and finally the dispatched transmission customers must then submit it e-tags to the AESO. In addition, time is also a factor in that after T-85 a constraint might not be detected until moments before T-20. Given the complexity of scheduling intertie transactions and the potential short timeframe the Commission considers that any resulting stranded capacity discovered between T-85 and T-20 is one of the inherent minor complications of operating interties in an electricity market two hours prior to the start of a settlement interval that an ATC allocation rule cannot reasonably be expected to eliminate or reduce more significantly.


5.3.8 Rule fails to contemplate future interties

321. TransCanada submitted the Proposed ATC Rule is insufficiently transparent because it is not robust enough to accommodate future interties. The Proposed ATC Rule does not account for and respect the respective contributions to AIC from a new intertie so that a new intertie will not be able to predict how much AIC it will be allocated, and there is no way to quantify the impact of future interties.246

322. NaturEner submitted that the Proposed ATC Rule establishes a principle for how allocation would work, and that the interaction of a new intertie with the Proposed ATC Rule

245 Exhibit 0152.02, Coalition Rebuttal Evidence, July 20, 2012, pages 15-16. 246 Exhibit 0272.03, TransCanada Argument, October 15, 2012, page 47.



would be dependent on where the new intertie was coming from and the characteristics of that intertie.247

323. The AESO submitted that while the Proposed ATC Rule would require changes to add future interties, as each intertie is specifically named in the Proposed ATC Rule and each has specific characteristics, the methodology is robust enough to accommodate the addition of any future interties.248

Commission finding

324. As stated in Section 20(1)(c) of the Electric Utilities Act, the AESO may make rules respecting the operation of the interconnected electric system, which would include allocating ATC among interties. In regards to quantifying the expected impact of future interties on existing interties, the Commission considers that intertie proponents, just like generators, are capable of forecasting potential future scenarios to assess consequences to their projects. The Commission considers that the AIES interaction with a new intertie would depend on the characteristics of the new intertie, which may vary greatly from project to project. The Proposed ATC Rule may require changes to add future interties. The Proposed ATC Rule provides an acceptable principle for allocation of ATC between interties for the immediate future.

325. The Commission finds that predicting the exact changes which the future may dictate are required or desirable is sufficiently uncertain and unpredictable that confirmation of the Proposed ATC Rule should not be denied for that reason.


5.3.9 Summary of Commission findings – technically deficient

327. In summary, the Commission is not persuaded on the grounds raised by the MPOs that the Proposed ATC Rule is technically deficient.

247 Exhibit 0282.01, NaturEner Argument, October 29, 2012, pages 15. 248 Exhibit 0281.02, AESO Argument, October 29, 2012, page 24.



6 Relief request and order

328. Given that the Commission finds that none of the grounds for objection to the Proposed ATC Rule have been established, this decision does not summarize or address the relief sought by the MPOs.

329. The AESO requested that the Commission confirm the Proposed ATC Rule, pursuant to section 20.5(1)(a) of the Electric Utilities Act, with an effective date no later than the commercial operation date of MATL.249

Commission findings

330. Section 20.5 of the Electric Utilities Act authorizes the Commission, after hearing an objection to an ISO rule, to confirm, disallow or direct the ISO to change the ISO rule or a provision of the ISO rule.

331. The Commission has not been persuaded that the Proposed ATC Rule is against the public interest or the FEOC operation of the market or is technically deficient.

332. The Proposed ATC Rule is confirmed and will come into effect no later than the commercial operation date of the MATL intertie, as requested by the AESO. The AESO is directed to immediately notify market participants and the Commission of this effective date once it has been ascertained.

Dated on February 1, 2013 The Alberta Utilities Commission (original signed by) Tudor Beattie, QC Panel Chair (original signed by) Bill Lyttle Commission Member (original signed by) Moin Yahya Acting Commission Member 250 249 Exhibit 0281.02, AESO Argument, page 35. 250 On October 3, 2012, O.C. 306/2012 rescinded the appointment of Dr. Yahya as a member of the Commission

and nominated him as an acting member of the Commission until October 2, 2017.



Appendix 1 – Proceeding participants

Name of Organization (Abbreviation) Counsel or Representative

Witnesses

Alberta Electric System Operator (AESO) James Smellie Lisa Jamieson

Miranda Keating Erickson, Director Market Design Kevin Dawson, Senior Program Manager Doug Simpson, Director Market Operations, Market Services Judy Chang, Principal, The Brattle Group.

ATCO Power Ltd. (ATCO Power) Marie Buchinskii Allison Sears

Carl Fuchshuber, VP Commercial Strategic Planning Horst Klinkenborg, Manager of Regulatory and Strategic Planning

British Columbia Hydro and Power Authority (BC Hydro) Jeff Christian

Gordon Doyle, Tariff and Contracts Manager Martin Huang, VP Grid Operations

Capital Power Corporation (Capital Power) Alan Ross Shaun Pillott

Cargill Limited (Cargill) – part of the Coalition Philip Pauls

Robert Walker, Director NA Transmission and Origination

Consumers Coalition of Alberta (CCA) J.A. Wachowich

Montana Alberta Tie Ltd c/o Enbridge Inc. (Enbridge/MATL) David Holgate Matthew Synnott

Lino Luison, VP Financial Partnerships, Enbridge Inc. Craig Baker, Retired, American Electric Power Co. Robert Baker, VP Teshmont Consultants LP Richard Stout, Executive Director, Association of Major Power Customers of BC Cliff Hamal, Managing Director, Navigant Economics Inc. Julie Carey, Director, Navigant Economics Inc.

Morgan Stanley Capital Group Inc. (Morgan Stanley) Dennis Langen Lisa Cherkas

Alireza Sedighzadeh Yazdi, Executive Director Jasper Wright, Associate Julia Frayer, Partner and Managing Director, London Economics International LLC.

NaturEner Energy USA, LLC (NaturEner) Rosa Twyman Kimberly Howard Erica Young

Chris Hodge, VP Commercial Operations North America

NorthPoint Energy Solutions Inc.(NorthPoint) – part of the Coalition Rangi Jeerakathil

Dean Jones, Manager Energy Trading



Name of Organization (Abbreviation) Counsel or Representative

Witnesses

PowerEx Corporation (PowerEx) – part of the Coalition Chris Sanderson Clara Ferguson

Arne Olson, Partner, Energy and Environmental Economics Inc. Donald Martin, Executive Consultant Gordon Dobson-Mack, Transmission Issues Manager Khosro Kabiri, Senior Consultant, Powertech Labs Inc. Michael MacDougall, Director Trade Policy and IT Robert Knecht, Industrial Economics Inc.

Saskatchewan Power Corporation (SaskPower) Rangi Jeerakathil

Wayne Guttormson, Supervisor Interconnections Paul Kos, Managing Director, Power System Solutions International Inc.

TransCanada Energy (TransCanada) Gordon Nettleton Azalea Jin

Vince Kostesky, Director Market Services Western Power Janene Taylor, Manager of Market Services Western Power Roger Williams, Manager Short Term Trading Operations and Analytics Craig Roach, President, Boston Pacific Company, Inc. Vincent Musco, Project Manager, Boston Pacific Company, Inc.

Utilities Consumer Advocate (UCA) Matthew Keen

Kevin Phillips, Principal, Phillips Partners Inc.

Alberta Utilities Commission

Commission Panel T. Beattie, QC, Panel Chair B. Lyttle, Commission Member M. Yahya, Acting Commission Member Commission Staff J. Petch (Commission counsel) A. Davison (Market Analyst) G. Andrews (Market Analyst) A. Chen (Engineering Specialist) T. Wilde (Engineer in Training)



Appendix 2 – Abbreviations

Abbreviation Name in Full

AESO Alberta Electric System Operator

AB-BC Intertie connecting Alberta and British Columbia

AB-SK Intertie connecting Alberta and Saskatchewan

AC Alternating current

AIC Alberta interchange capability

AIES Alberta Interconnected Electric System

ATC Available transfer capability

ATCO Power ATCO Power Ltd.

AUC Alberta Utilities Commission

BC Hydro British Columbia Hydro and Power Authority

BCTC British Columbia Transmission Corporation (predecessor to BC Hydro)

BCUC British Columbia Utilities Commission

Capital Power Capital Power Corporation

Cargill Cargill Limited

CCA Consumers Coalition of Alberta

Coalition PowerEx, NorthPoint and Cargill formed a coalition to make joint submissions in this proceeding

DC Direct current

Enbridge/MATL Montana Alberta Tie Ltd. c/o Enbridge Inc.

ENMAX ENMAX Energy Corporation

E-tags Export transaction schedule submissions

ISO Independent System Operator

LIFO Last-in-first-out

LSSi Load shed service for imports

MATL Montana Alberta Tie Ltd.

Morgan Stanley Morgan Stanley Capital Group Inc.

MPO Market participant objector

MRO Midwest Reliability Organization

NaturEner NaturEner USA, LLC

NEB National Energy Board

NERC North American Electric Reliability Corporation

NorthPoint NorthPoint Energy Solutions Inc.

OPP Operating policies and procedures of the AESO



PowerEx PowerEx Corporation

Proposed ATC Rule Proposed ISO rule Section 203.6: Available Transfer Capability and Transfer Path Management

RMO Reverse merit order

SaskPower Saskatchewan Power Corporation

SATL Saskatchewan-Alberta Tie Line Project Inc.

TCM Transmission constraints management

TransCanada TransCanada Energy Ltd.

UCA Utilities Consumer Advocate

WECC Western Electricity Coordinating Council

WPM Rule Wind power management rule



Appendix 3 – PROPSED ISO RULES SECTION 203.6: AVAILABLE TRANSFER CAPABILTY AND TRANSFER PATH MANAGEMENT

Proposed New ISO Rules Part 200, Markets

Division 203, Energy Markets Section 203.6

Available Transfer Capability and Transfer Path Management

Final Proposed Filing Draft

December 5, 2011

Applicability

1 Section 203.6 applies to:

(a) a pool participant seeking to exchange or transact an import or export interchange transaction; and

(b) the ISO.

Capability Limits Determinations by the ISO

2(1) The ISO must determine and post on the AESO website the following capability limits in MW prior to each settlement interval, and also on an as required basis when interconnected electric system operating conditions change:

(a) the Alberta interchange capability;

(b) the import and export capability of the combined British Columbia and Montana transfer paths; and

(c) the import available transfer capability and export available transfer capability for each of the British Columbia, Montana and Saskatchewan transfer paths.

(2) Once the ISO has determined the limits under subsection 2(1), it must ensure that:

(a) the amount in MW of all transmission service for all import and export interchange transactions for all transfer paths does not exceed the Alberta interchange capability limit referenced in subsection 2(1)(a);

(b) the amount in MW of all transmission service for all import and export interchange transactions for the combined British Columbia and Montana transfer paths does not exceed the combined limit referenced in subsection 2(1)(b); and

(c) the amount in MW of all transmission service for all import and export interchange transactions for an individual transfer path does not exceed the limit for that transfer path referenced in subsection 2(1)(c).

Filed with the Commission: 2011-12-05 Page 1 of 8



Total Transfer Capability Determinations by the ISO

3(1) The ISO must determine the import total transfer capability and the export total transfer capability for an individual transfer path, in order to determine the import available transfer capability and the export available transfer capability for that transfer path.

(2) The ISO must make the determinations under subsection 3(1) with reference to the applicable provisions of any related reliability standards.

Available Transfer Capability Determinations by the ISO for a Transfer Path

4(1) The ISO must use the import available transfer capability and the export available transfer capability limits as referenced under subsection 2(1)(c) for an individual transfer path, as the maximum capability for scheduling interchange transactions on that transfer path.

(2) The ISO must post on the AESO website the import available transfer capability and the export available transfer capability as determined for an individual transfer path.

(3) The ISO must post on the AESO website as soon as is reasonably practical any change to the import available transfer capability or the export available transfer capability for an individual transfer path.

Submission of Interchange Transaction Bids and Offers by a Pool Participant

5(1) Notwithstanding subsection 3.5.2 of the ISO rules, Submission Timing, a pool participant with an import or export energy interchange transaction must submit through the Energy Trading System the import offer or export bid for the interchange transaction, as applicable, no later than two (2) hours prior to the start of the settlement interval in order for the interchange transaction to be included in the energy market merit order.

(2) A pool participant with any form of interchange transaction must use all reasonable efforts to procure transmission service from applicable transmission service providers in an amount in MW at least equal to the available capability of the interchange transaction, which reasonable efforts must include:

(a) determining whether there is transmission service posted by the applicable transmission service providers and available for that interchange transaction; and

(b) submitting a request to the applicable transmission service providers to procure the transmission service, if it has been posted and is available.

(3) If after complying with subsection (2):

(a) the pool participant is unable to procure all or a portion of the requested transmission service for an energy interchange transaction; or

(b) the transmission service for an energy interchange transaction is curtailed after procurement either by any transmission service provider or the ISO;

then such a circumstance is a reason the pool participant must submit a restatement of available capability, and may be the basis for the determination of an acceptable operational reason under subsection (iv) of that definition.




(4) For any pool participant with an interchange transaction, if due to a determination by the ISO under subsection 10 the amount in MW of the interchange transaction on an individual transfer path exceeds the individual transfer path available transfer capability allocation as determined under that subsection, then that circumstance is a reason the pool participant may submit a restatement of available capability to the level of the allocation, and may be the basis for the determination of an acceptable operational reason under subsection (iv) of that definition.

Submission of E-tags by Pool Participants

6(1) Pool participants with any import or export interchange transactions who have acquired transmission service must submit e-tags to the ISO for the interchange transactions.

(2) The ISO must receive e-tags no later than twenty (20) minutes prior to the start of the settlement interval in order for the energy components of the interchange transactions to be included in an interchange schedule referenced in subsection 8.

(3) A pool participant must submit one (1) or more e-tags for an energy interchange transaction such that the final total amount in MW agrees with the available capability of the single source asset:

(a) as stated two (2) hours prior to the start of the settlement interval; or

(b) as may be restated in accordance with the provisions of this section 203.6, but in any event the final total amount in MW must not exceed the available capability of the single source asset as stated at two (2) hours prior to the start of the settlement interval.

(4) If:

(a) the pool participant is unable to procure transmission service, or the transmission service is curtailed by any transmission service provider or the ISO, as referenced under subsection 5(3); or

(b) there is any other change in the available capability for the sink asset or the source asset, as applicable;

then the pool participant must submit, as applicable:

(i) an energy restatement in accordance with either subsection 3.5.3.2 or subsection 3.5.4.2 of the ISO rules, Mandatory Energy Restatements; or

(ii) an ancillary services restatement in accordance with subsection 3.6.3 of the ISO rules, Restatements.

Validation of E-Tags by the ISO

7(1) The ISO must validate e-tags for interchange transactions in accordance with the provisions of this subsection 7.

(2) An e-tag must be validated by the ISO prior to the e-tag being included in an interchange schedule.

(3) The ISO must validate an e-tag with reference to the provisions of the reliability standards, INT-006-AB-2 Response to Interchange Authority.

(4) The ISO must reject an e-tag:




(a) if the interchange transaction is not being transacted by a pool participant;

(b) for an import interchange transaction if the source balancing authority is in the WECC and the sink balancing authority is the ISO, and the source balancing authority is not carrying reserves allocated for that import interchange transaction; or

(c) if the e-tag is not fully completed.

(5) If the provisions of this subsection 7 otherwise are complied with, then the ISO may validate and include in the interchange schedule any e-tags that are submitted after the twenty (20) minute deadline set out in subsection 6(2).

Interchange Schedules and Dispatches by the ISO

8(1) Subject to the provisions of this section 203.6, the ISO must include in the interchange schedule the energy components of interchange transactions if the e-tags for the interchange transactions have been:

(a) received by the submission deadline set out in subsection 6(2); and

(b) validated under subsection 7.

(2) The ISO must determine the interchange schedule for each transfer path before the start of the settlement interval, taking into account the allocation and constraint management procedures and sequencing set out in subsection 10 and subsection 11.

(3) Each interchange schedule period must be equal to the settlement interval, unless the ISO has an agreement with an adjacent balancing authority specifying an alternative interchange schedule start and end time for an individual transfer path, and in that event the timing of the interchange schedule for the transfer path must be governed by the form of agreement.

(4) The ISO must treat the energy component of a scheduled interchange transaction as a dispatch in accordance with the applicable energy market merit order.

(5) The ISO must not make any changes to an interchange schedule for a transfer path except if required to accommodate:

(a) the delivery of external supplemental reserves, spinning reserves or contingency reserves;

(b) a matter of reliability on the interconnected electric system, or a similar matter which may occur in any other balancing authority area;

(c) an emergency or a system emergency on the interconnected electric system or in any other balancing authority area;

(d) a supply shortfall or supply surplus matter; or

(e) any curtailments resulting from the procedures and sequencing set out in subsection 10 and subsection 11.

(6) If the ISO is required to accommodate any matter referred to in subsection 8(5), then the ISO must issue the resulting interchange schedule changes.




Saskatchewan Inadvertent Energy Management

9 If the ISO is required to manage an amount of inadvertent energy on the Saskatchewan transfer path, then:

(a) the inadvertent energy is not eligible to set the pool price; and

(b) inadvertent energy payback on the Saskatchewan transfer path must not exceed twenty-five (25) MW.

Available Transfer Capability Allocations for Transfer Paths

10(1) At approximately eighty-five (85) minutes prior to a settlement interval, the ISO must determine whether the capability limits under subsection 2 may be exceeded, and if so then the ISO must determine the individual transfer path available transfer capability allocations in accordance with the following procedures:

(a) the ISO must calculate the net interchange transaction amount in MW, at each potential system marginal price, taking into account:

(i) the energy interchange transaction amounts in MW, and the prices for bids and offers;

(ii) the interchange transaction amount in MW for ancillary services; and

(iii) applicable counterflows; and

(b) the ISO may exclude any wheel through transaction amounts in MW if those amounts will not result in any limits or allocations under this section 203.6 being exceeded.

(2) The ISO must comply with the following additional procedures in the following sequence to determine the allocation of each of the individual transfer path available transfer capability allocations:

(a) the net amount in MW of all interchange transactions for the individual transfer path must be compared to the limit determined for that individual transfer path as referenced in subsection 2(1)(c), and:

(i) if that net amount is equal to or greater than the limit, then the allocation must be set at that limit; and

(ii) if that net amount is less than the limit, then the allocation must be set at that net amount;

(b) for the British Columbia and Montana transfer paths, the sum in MW of their individual transfer path allocations calculated under subsection 10(2)(a) must be compared to the combined British Columbia and Montana transfer path limit referenced in subsection 2(1)(b);

(c) if the combined transfer path limit of subsection 2(1)(b) is not exceeded, then the allocations must remain as determined in accordance with subsection 10(2)(a), but if it is exceeded, then a further allocation must be done in accordance with the following sequence in order to ensure the combined transfer path limit as determined under subsection 2(1)(b) is not exceeded:

(i) first, the British Columbia, or the Montana, or both the British Columbia and the Montana transfer path allocations must be reduced as




necessary by the applicable ancillary services type interchange transaction amounts in MW;

(ii) second, the British Columbia, or the Montana, or both the British Columbia and the Montana transfer path allocations must be reduced as necessary by the applicable energy interchange transaction amounts in MW, with the reduction being in reverse merit order based on bid and offer prices; and

(iii) third, if there are equally priced British Columbia and Montana energy interchange transactions, then the British Columbia and Montana allocations must be reduced on a pro rata basis using the following formula:

the MW allocation for each of the Montana and British Columbia transfer paths as determined in accordance with subsection 10(2)(a), as may be reduced under subsections 10(2)(c)(i) and 10(2)(c)(ii);

divided by

the sum in MW calculated under in subsection 10(2)(b) as may be reduced under subsections 10(2)(c)(i) and 10(2)(c)(ii);

multiplied by

the amount by which that sum exceeds the combined British Columbia and Montana transfer path limit referenced in subsection 2(1)(b);

(d) the allocation resulting from subsection 10(2)(c) plus the Saskatchewan transfer path allocation calculated under subsection 10(2)(a) must then be compared to the Alberta interchange capability limit referenced in subsection 2(1)(a); and

(e) if the Alberta interchange capability limit is not exceeded, then the allocations must remain as determined in accordance with subsections 10(2)(a) and 10(2)(c), but if that limit is exceeded, then a further allocation of available transfer capability must be done in accordance with the following sequence in order to ensure that the Alberta interchange capability limit as determined under subsection 2(1)(a) is not exceeded:

(i) first, any individual one (1), or any combination of the British Columbia, Montana, and Saskatchewan transfer path allocations must be reduced as necessary by the applicable ancillary service type interchange transaction amount in MW;

(ii) second, any individual one (1), or any combination of the British Columbia, Montana, and Saskatchewan transfer path allocations must be reduced as necessary by the applicable energy interchange transaction amounts in MW, with the reduction being in reverse merit order based on bid and offer prices; and

(iii) third, if there are equally priced British Columbia, Montana and Saskatchewan energy interchange transactions, then the British Columbia, Montana and Saskatchewan allocations must be reduced on a pro rata basis using the following formula:




the MW allocation for each of the Montana and British Columbia transfer paths as determined in accordance with subsection 10(2)(c) and the Saskatchewan transfer path allocation under subsection 10(2)(a), as may be reduced under subsections 10(2)(e)(i), and 10(2)(e)(ii);

divided by

the sum in MW referred to in subsection 10(2)(d), as may be reduced under subsections 10(2)(e)(i) and 10(2)(e)(ii);

multiplied by

the amount by which that sum exceeds the Alberta interchange capability limit referenced in subsection 2(1)(a);

(3) At approximately eighty-five (85) minutes prior to a settlement interval, the ISO must post on the AESO website:

(a) the total in MW of all energy import offers and export bids received for each transfer path and the combinations of transfer paths referenced under subsection 2, at two (2) hours prior to the start of the settlement interval in accordance with subsection 5(1);

(b) the limits referenced under subsection 2; and

(c) all allocations made under this subsection 10.

(4) If, after eighty-five (85) minutes prior to a settlement interval, any of the limits referenced in subsection 2 have decreased, then the ISO must curtail interchange transactions in accordance with the procedures and sequence set out in subsection 11.

Transfer Path Constraint Management

11(1) If, after carrying out the procedures set out in subsection 10, within fifteen (15) minutes prior to the start of the settlement interval and based on the e-tags submitted under subsection 6 the limits referenced in subsection 2 are still exceeded, then the ISO must curtail interchange transactions in accordance with the sequential procedures set out in this subsection 11.

(2) The ISO must determine the effective interchange transactions for mitigating a constraint caused by limits being exceeded at the Alberta interchange capability level, the combined Montana and BC transfer path capability level, or at each individual transfer path level.

(3) The ISO may determine that any wheel through transaction is not effective in mitigating a constraint, based on its analysis under subsection 11(2).

(4) The ISO must comply with the following procedures in the following sequence to mitigate the remaining constraint:

(a) assess all interchange transactions for transmission services against the limits referenced under subsection 2 and allocations made under subsection 10, and determine the interchange transactions that will be effective in mitigating the constraint;

(b) curtail the transmission service of interchange transactions under the sequencing set out in subsection 11(4)(c), mitigating the constraint in the following order at the following levels, where effective:




(i) an individual transfer path limit level;

(ii) the combined Montana and British Columbia transfer path level; or

(iii) the Alberta interchange capability level; and

(c) curtail at the effective level:

(i) inadvertent energy payback interchange transactions, prior to the curtailment of any interchange transactions on the Saskatchewan transfer path;

(ii) transmission services of any effective interchange transactions for ancillary services;

(iii) transmission services of any effective energy interchange transactions based on bid and offer prices in reverse merit order; and

(iv) transmission services of any effective energy interchange transactions on a pro rata basis in accordance with the following formula:

scheduled amount of each effective interchange transaction;

multiplied by

total amount necessary to mitigate the constraint;

divided by

total scheduled amount of all effective interchange transactions.

Revision History

Effective Description

yyyy/mm/dd