u~ · alberta utilities commission in the matter of the need for the wabasca 720s substation...

May 14, 2015

Attention: Wade Vienneau Executive Director- Facilities Alberta Utilities Commission Fifth Avenue Place 4th Floor, 425 - 1 Street SW Calgary, AB T2P 3L8

Dear Mr. Vienneau:

Re: Application to the Alberta Utilities Commission (AUC) for approval of the Wabasca 720S Substation Modification Needs Identification Document

Please find enclosed the Alberta Electric System Operator (AESO) application for approval of the Needs Identification Document (NID) for the proposed Wabasca 720S Substation Modification pursuant to Section 34 of the Electric Utilities Act.

The AESO understands that ATCO Electric Ltd. will file the related facilities application shortly. The AESO requests that the Commission combine the NID and the facilities application and consider them together pursuant to Section 15.4 of the Hydro and Electric Energy Act.

Please do not hesitate to contact the below if you have questions or concerns regarding the foregoing:

Melissa Mitcheii-Moisson Senior Regulatory Coordinator [email protected] 403-539-2948

sjre}'

u~ Manager, Regulatory

2500, 330-5th Avenue SW, Calgary, Alberta T2P OL4 Phone: 403-539-2450 Fax: 403-539-2949 www.aeso.ca www.poweringalberta.com

Alberta Utilities Commission

In the Matter of the Need for the Wabasca 720S Substation Modification

And in the matter of the Electric Utilities Act, S.A. 2003, c. E-5.1, the Alberta Utilities Commission Act, S.A. 2007, c. A-37.2, the

Hydro and Electric Energy Act, R.S.A. 2000, c. H-16, the Transmission Regulation, AR 86/2007 and Alberta Utilities

Commission Rule 007, all as amended

Application of the Alberta Electric System Operator for Approval of the

Wabasca 720S Substation Modification Needs Identification

Document

Wabasca 720S Substation Modification Needs Identification Document

Alberta Electric System Operator

1 May 14, 2015

PART A - APPLICATION

1 Introduction

1.1 Application – Pursuant to Section 34(1)(c) of the Electric Utilities Act (Act), and

in accordance with further provisions set out in legislation,1 the Alberta Electric System

Operator (AESO) applies to the Alberta Utilities Commission (Commission) for approval

of the Wabasca 720S Substation Modification Needs Identification Document

(Application).

1.2 Application Overview – ATCO Electric Ltd. (ATCO),2 as the legal owner of the

electric distribution facilities (DFO) in the Wabasca area (AESO Planning Area 25, Fort

McMurray), has requested transmission system access to supply a new industrial load

in the area with a corresponding Demand Transmission Service increase of 8 MW.

ATCO’s request can be met by modifying the existing Wabasca 720S substation,

including the addition of a 25 kV breaker (the “Proposed Transmission Development”,

as further described in Section 2.2). The requested in-service date for the Proposed

Transmission Development is mid-2016.

This Application describes the need to respond to the DFO’s request for system access

service. Having followed the AESO Connection Process,3 the AESO has determined

that the Proposed Transmission Development provides a reasonable opportunity for the

DFO to exchange electricity. The Proposed Transmission Development is aligned with

the AESO’s long-term plan for the Fort McMurray area. The AESO, in accordance with

1 The Alberta Utilities Commission Act, S.A. 2007, c. A-37.2, the Hydro and Electric Energy Act, R.S.A.

2000, c. H-16, the Transmission Regulation, AR 86/2007 and Alberta Utilities Commission Rule 007, all as amended.

2 ATCO acts as both the legal owner of distribution facilities (DFO) and the legal owner of transmission

facilities (TFO) as applicable to its specific business functions.

3 For information purposes, refer to note iv of Part C of this Application for more information on the

AESO’s Connection Process.



2 May 14, 2015

its responsibility to respond to requests for system access service, submits this

Application to the Commission for approval.4,5

1.3 AESO Directions to the TFO – During the AESO Connection Process, the

AESO issued various directions to ATCO, as the legal owner of transmission facilities

(TFO), including direction to assist the AESO in preparing this Application.6

4 For information purposes, some of the legislative provisions relating to the AESO’s planning duties and

duty to provide system access service are referenced in notes i and ii of Part C of this Application.

5 Note v of Part C of this Application describes the Application scope in more detail.

6 The directions are described in more detail in the following sections of this Application and in Part C,

note vi.



3 May 14, 2015

2 Need Overview and Proposed Transmission Development

2.1 Duty to Provide Transmission System Access Service – The AESO, pursuant

to its responsibilities under Section 29 of the Act, must provide system access service

on the transmission system in a manner that gives all market participants (in this case

the DFO), a reasonable opportunity to exchange electric energy and ancillary services.

The DFO, in executing its duties as defined under Section 105(1)(b) of the Act, has

determined that the Proposed Transmission Development is the preferred development

to supply a new industrial load in the Wabasca area. The DFO has made the

appropriate applications to the AESO to obtain transmission system access service.7

Through the AESO Connection Process, the AESO, the DFO, and the TFO have

collaborated to determine the characteristics of the Proposed Transmission

Development and assess the impacts of connecting the Proposed Transmission

Development to the transmission system. The AESO has issued directions to the TFO

to prepare a Facility Proposal8 to meet the DFO’s identified need.

2.2 Proposed Transmission Development – The Proposed Transmission

Development involves modifying the Wabasca 720S substation, including the following

major elements:

1. Add a 25 kV breaker; and

2. Modify, alter, add or remove equipment, including switchgear, and any

operational, protection, control and telecommunication devices required to

undertake the work as planned and ensure proper integration with the

transmission system.9

7 For information purposes, some of the duties of the DFO are described in note vii of Part C of this

Application.

8 Also referred to as facility application, or FA, under Commission Rule 007.

9 Details and configuration of equipment required for the Proposed Transmission Development, including

substation single-line diagrams, are more specifically described in the AESO’s Functional Specification included in the TFO’s Facility Proposal. Also, further details will be determined as detailed engineering progresses and DFO operating requirements are finalized. Routing and/or siting of transmission facilities do not form part of this Application and are addressed in the TFO’s Facility Proposal. This is subject to



4 May 14, 2015

2.3 Proposed Transmission Development Cost Estimates – The AESO directed

the TFO to prepare a cost estimate for the Proposed Transmission Development. The

TFO estimated the in-service cost of the Proposed Transmission Development,

described in Section 2.2, to be approximately $2 million ($2016).10 In accordance with

the ISO Tariff, the AESO has determined that there are no system-related costs

associated with the Proposed Transmission Development.

2.4 Transmission Development Alternatives – In addition to the Proposed

Transmission Development, the following transmission alternative was identified:

1. Add a new POD substation – This entails adding a new 240/25 kV substation

connected to the existing transmission line 9L56 via an in-and-out connection

configuration. This alternative also involves adding a 240 kV transformer, three

240 kV breakers, and approximately 5 km of new double circuit 240 kV

transmission line. This alternative was ruled out due to the anticipated higher

cost associated with increased transmission facility development.

The Proposed Transmission Development was selected by the DFO as the lower-cost

option and forms the basis for the cost estimates and the Connection Assessment

described herein.11

2.5 Connection Assessment – Load flow, voltage stability and short circuit

analyses were conducted to assess the impact that the Proposed Transmission

Development and the associated load would have on the transmission system. Load

flow and short circuit analyses were conducted prior to and following connection of the

Proposed Transmission Development and voltage stability analysis was performed

following connection of the Proposed Transmission Development. These analyses

change as routing and/or siting is finalized by the TFO. Distribution facilities that may subsequently be connected to the Proposed Transmission Development are the responsibility of the DFO and are not included in the Application.

10 Further details of this cost estimate can be found in Appendix B, with an approximate accuracy level of

+20%/-10%.

11 The DFO considered and ruled out load shifting on the distribution system. The DFO’s report detailing

this analysis is included as Appendix E, Sections 3 and 4.



5 May 14, 2015

indicate that the Proposed Transmission Development will not adversely impact

transmission system performance.12

2.6 Transmission Interdependencies – The AESO’s forecasts for the Fort

McMurray area include load consistent with the load to be served from the Proposed

Transmission Development.13 The AESO’s corporate load forecasts are used by the

AESO to assess the adequacy of the regional transmission system and to identify future

transmission system expansion and enhancement plans. Therefore, the need to serve

the load associated with the Proposed Transmission Development is consistent with the

AESO’s long-term plans for the region. Future AESO needs identification documents in

the Fort McMurray area will assume the Proposed Transmission Development will be in-

service for the date specified, unless new information indicates otherwise.

2.7 AESO Participant Involvement Program – The AESO directed the TFO to

assist the AESO in conducting a participant involvement program (PIP), in accordance

with requirement NID14 and Appendix A2 of Commission Rule 007. Between

September 2014 and April 2015, the TFO and the AESO used various methods to notify

occupants, residents, landowners, government bodies, agencies and stakeholder

groups (collectively, the stakeholders) of the need for the Proposed Transmission

Development in the area where transmission facilities could be installed to address the

identified need. Additionally, the AESO notified the public in the area where

transmission facilities could be installed to address the identified need, of its intention to

file this Application with the Commission for approval. No concerns or objections have

been raised regarding the need for the Proposed Transmission Development.14

2.8 Information Regarding Rule 007, Section 6.1 - NID13 – The AESO has been

advised that the TFO’s Facility Proposal addresses the major aspects listed in

12

The Connection Assessment is included as Appendix A.

13 Section 6.2 of the AESO’s 2014 Long-term Outlook discusses the Northeast Region, which includes the

Proposed Transmission Development area.

14 Further information regarding the AESO’s PIP for this Application is included in Appendix C.



6 May 14, 2015

Commission Rule 007, Section 6.1 - NID13.15 In consideration of that fact, and as the

filing of the Application is combined with the TFO’s Facility Proposal, the AESO has not

undertaken a separate assessment of the sort contemplated in Commission Rule 007,

Section 6.1 – NID13.

2.9 Approval is in the Public Interest – Having regard to the following:

the transmission planning duties of the AESO as described in Sections 29, 33

and 34 of the Act;

the System Access Service Request;

the DFO’s Distribution Deficiency Report;

the Connection Assessment;

information obtained from AESO PIP Activities; and

the AESO’s long-term transmission system plans;

it is the conclusion of the AESO that the Proposed Transmission Development provides

a reasonable opportunity for the market participant to exchange electricity. In

consideration of these factors, the AESO submits that approval of this Application is in

the public interest.

15

Please refer to the letter included as Appendix D of this Application.



7 May 14, 2015

3 Request to Combine this Application with the Facility Proposal for Consideration in a Single Process

3.1 Pursuant to Subsection 35(1) of the Act, the AESO has directed the TFO to

prepare a Facility Proposal to meet the need identified. The AESO understands that the

TFO’s Facility Proposal will be filed shortly.16 The AESO requests, and expects the TFO

will request, that this Application be combined with the Facility Proposal for

consideration by the Commission in a single process. This request is consistent with

Section 15.4 of the Hydro and Electric Energy Act and Section 6 of Commission Rule

007.

3.2 While it is believed that this Application and the Facility Proposal will be

materially consistent, the AESO respectfully requests that in its consideration of both,

the Commission be mindful of the fact that the documents have been prepared

separately and for different purposes. The purpose of this Application is to obtain

approval of the need to respond to the DFO’s request for system access service and

provide a preliminary description of the manner proposed to meet that need. In contrast,

the Facility Proposal will contain more detailed engineering and designs for the

Proposed Transmission Development and seek approval for the construction and

operation of specific facilities.

16

The AESO understands that the TFO intends to file a Facility Proposal relating to this Application to be titled Application for Alterations at Wabasca 720S Substation.


4 Relief Requested

4 .1 The AESO submits that its assessment of the need to meet the market

participant's request for transmission system access service is technically complete and

that approval is in the public interest.

4.2 For the reasons set out herein, and pursuant to Section 34 of the Act, the AESO

requests that the Commission approve this Application, including issuing an approval of

the need to respond to the market participant's request for system access service, and

to modify the Wabasca 720S substation, as follows:

A Add a 25 kV breaker; and

B. Modify, alter, add or remove equipment, including switchgear, and any

operational, protection, control and telecommunication devices required to

undertake the work as planned and ensure proper integration with the

transmission system.

All of which is respectfully submitted this 14th day of May 2015.

Doyle Su livan, P. Eng. Director, Regulatory


8 May 14, 2015



9 May 14, 2015

PART B – APPLICATION APPENDICES

The following appended documents support the Application (Part A).

APPENDIX A Overview of AESO Connection Process – Appendix A contains

the Connection Engineering Study Report for AUC Application Wabasca 720S – 25 kV

Breaker Addition that assesses the transmission system performance prior to and

following the connection of the Proposed Transmission Development. As part of the

AESO Connection Process, the DFO engaged a consultant to conduct the connection

assessment (Study). The AESO defined the Study scope, and provided the system

models and Study assumptions. The AESO also reviewed this report and its

conclusions, and finds the Study acceptable for the purposes of assessing the impacts

of the Proposed Transmission Development on the transmission system.

APPENDIX B TFO Capital Cost Estimates – Appendix B contains detailed cost

estimates corresponding to the Proposed Transmission Development. These estimates

have been prepared by the TFO at the direction of the AESO, to an approximate

accuracy level of +20%/-10%, which exceeds the accuracy required by Commission

Rule 007, NID11.

APPENDIX C AESO PIP – Appendix C contains a summary of the PIP activities

conducted regarding the need to respond to the market participant’s request for system

access service. Copies of the relevant materials distributed during the PIP are attached

for reference.

APPENDIX D Information Regarding Rule 007, Section 6.1 - NID13 – Appendix

D contains a letter provided by the TFO confirming that the seven major aspects of

Commission Rule 007, NID13 will be addressed within the TFO’s Facility Proposal.

APPENDIX E DFO Need for Development Report – Appendix E contains the

DFO’s AESO Connection Project # P1491 Wabasca 720S Distribution Deficiency

Report that provides information in support of the DFO’s request for system access

service, including describing the need for development.



10 May 14, 2015

APPENDIX F AESO Transmission Planning Criteria – Basis and

Assumptions – The AESO has recently revised the Transmission Reliability Criteria,

Part II Transmission System Planning Criteria, Version 0, dated March 11, 2005

primarily to remove criteria that are now included in the Transmission Planning (TPL)

Standards.17 Appendix F contains the Transmission Planning Criteria – Basis and

Assumptions, Version 1, which includes the applicable thermal and voltage limits in

support of the TPL standards. Planning studies that are included in this Application

meet all the performance requirements of the specified TPL standards (TPL-001-AB-0,

TPL-002-AB-0, and specified contingencies associated with TPL-003-AB-0).

17

TPL Standards are included in the current Alberta Reliability Standards.



11 May 14, 2015

PART C – REFERENCES

i. AESO Planning Duties and Responsibilities – Certain aspects of AESO duties and

responsibilities with respect to planning the transmission system are described in the Act. For

example, Section 17, Subsections (g), (h), (i), and (j), describe the general planning duties of the

AESO.18

Section 33 of the 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.” Where, as in this case, the market participant (refer to note ii

below) is requesting system access service to meet its distribution planning needs, and the

request requires or may require the expansion or enhancement of the capability of the

transmission system, the AESO must prepare and submit for Commission approval, as per

Section 34(1)(c), a needs identification document that describes the need to respond to requests

for system access service, including the assessments undertaken by the AESO regarding the

manner proposed to address that need. Other aspects of the AESO’s transmission planning

duties and responsibilities are set out in Sections 8, 10, and 11 of the Transmission Regulation.

ii. Duty to Provide Transmission System Access – Section 29 of the Act states that the AESO

“must provide system access service on the transmission system in a manner that gives all

market participants [the DFO in this case] wishing to exchange electric energy and ancillary

services a reasonable opportunity to do so.”

iii. AESO Planning Criteria – The AESO is required to plan a transmission system that satisfies

applicable reliability standards. Transmission Planning (TPL) standards are included in the

Alberta Reliability Standards, and are generally described at:

http://www.aeso.ca/rulesprocedures/17006.html.19

In addition, the AESO’s Transmission Planning Criteria – Basis and Assumptions is included in

Appendix F.

iv. AESO Connection Process – For information purposes, the AESO Connection Process, which

changes from time to time, is generally described at: http://www.aeso.ca/connect20

v. Application for Approval of the Need to Response to a Request for System Access Service

– This Application is directed solely to the question of the need to respond to a request for system

18

The legislation and regulations refer to the Independent System Operator or ISO. "AESO" and "Alberta Electric System Operator" are the registered trade names of the Independent System Operator.

19 This link is provided for ease of reference and does not form part of this Application.

20 This link is provided for ease of reference and does not form part of this Application.

http://www.aeso.ca/rulesprocedures/17006.html

http://www.aeso.ca/connect



12 May 14, 2015

access service, as more fully described in the Act and the Transmission Regulation. This

Application does not seek approval of those aspects of transmission development that are

managed and executed separately from the needs identification document approval process.

Other aspects of the AESO’s responsibilities regarding transmission development are managed

under the appropriate processes, including the ISO Rules, Alberta Reliability Standards and the

ISO Tariff, which are also subject to specific regulatory approvals. While the Application or its

supporting appendices may refer to other processes or information from time to time, the

inclusion of this information is for context and reference only.

Any reference within the Application to market participants or other parties and/or the facilities

they may own and operate or may wish to own and operate, does not constitute an application for

approval of such facilities. The responsibility for seeking such regulatory or other approval

remains the responsibility of the market participants or other parties.

vi. Directions to the TFO – Pursuant to Subsection 35(1) of the Act, the AESO has directed the

TFO, in whose service territories the need is located, to prepare a Facility Proposal to meet the

need identified. The Facility Proposal is also submitted to the Commission for approval. The TFO

has also been directed by the AESO under Section 39 of the Act to prepare a proposal to provide

services to address the need for the Proposed Transmission Development. The AESO has also

directed the TFO, pursuant to Section 39 of the Act and Section 14 of the Transmission

Regulation, to assist in the preparation of the AESO’s Application.

vii. Duties of owner of electric distribution systems – The duties of DFOs to make decisions

about building, upgrading and improving their electric distribution systems are described in

Section 105(1)(b) of the Act. The DFO, being responsible for electric distribution system planning,

determines its need for transmission system access service based on its own distribution

planning guidelines and criteria. While the DFO’s plans are considered during the AESO

Connection Process, the AESO, in executing its duties to plan the transmission system, does not

oversee electric distribution planning or the development of specific DFO planning criteria. The

AESO does, however, seek to ensure that DFO load growth forecasts used in the Connection

Process are consistent with AESO load growth forecasts as described in Part A of this

Application.

viii. Capital Cost Estimates – The provision of capital costs estimates in the Application is for the

purposes of relative comparison and context only. The AESO’s responsibilities in respect of

project cost reporting are described in the Transmission Regulation, including Section 25, and

ISO Rule 9.1.

APPENDIX A OVERVIEW OF AESO CONNECTION PROCESS

ATCOElectric

Connection Engineering StudyReport for AUC Application

Wabasca 720S — 25 kV Breker Addition

File No. 1491

Revision: 5

Revision Date: 2015-05-04

Name Date Signature

Prepared by: Hugo Murici Ayres, P. Eng.

Ac.y E ZOtSE

Reviewed by: Sharon Morganson, P. Eng.

APEGA Permit to Practice # P0850

Connection Engineering Study Report for AUC Application: Wabasca 720S – 25 kV Breaker Addition

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Executive Summary

ATCO Electric Ltd. (ATCO) has received a request from a customer to provide service to their in-situ oil sands plant located at LSD 6-12-81-24 W4M. As a result, a System Access Service Request (SASR) was submitted to the Alberta Electric System Operator (AESO) to increase the Demand for Transmission Service (DTS) for Wabasca 720S from 22 MW to 30 MW. Considering this 8.0 MW load increase along with other oilfield and industrial customers in the area, the total load forecast for Wabasca 720S for 2016 is approximately 46 MW. The requested in-service date (ISD) for this project is July 1, 2016.

Wabasca 720S substation is within the AESO Planning Sub-area 58 (Dover Sub-area), which is part of the AESO Planning Area 25 (Fort McMurray Area). The existing transformer capacity at Wabasca 720S is sufficient to facilitate the requested load increase. ATCO has requested transmission development to support the additional load.

Two transmission alternatives were identified for this project:

Alternative 1: Modify the existing Wabasca 720S substation by adding a new 25 kV breaker at Wabasca 720S substation;

Alternative 2: Add a new 240-25 kV POD substation.

Alternative 2 was not selected for further study as it involves more transmission system development compared to Alternative 1. Alternative 1 was studied to support the project load addition.

Load flow analysis was conducted for the pre- and post-connection 2016 winter and summer peak (2016 WP and 2016 SP) conditions to assess the impact of the requested Wabasca 720S substation modification on the transmission system. Voltage stability analysis was performed for the post-connection 2016 WP condition. Lastly, short circuit analysis was performed for the pre- and post-connection 2016 WP conditions and also for the post-connection 2023 winter peak (2023 WP) condition to determine the short circuit levels in the vicinity of the Wabasca 720S substation.

The results of the above studies show that there were no transmission thermal overloads, voltage criteria violations or voltage stability violations found with this project addition for the scenarios analyzed. Based upon the study results, Alternative 1 is the recommended alternative.


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Contents Executive Summary ................................................................................................................................... 11. Introduction ......................................................................................................................................... 4

1.1. Project ........................................................................................................................................... 41.1.1. Project Overview .................................................................................................................... 41.1.2. Load Component ................................................................................................................... 41.1.3. Generation Component ......................................................................................................... 4

1.2. Study Scope .................................................................................................................................. 51.2.1. Study Objectives .................................................................................................................... 51.2.2. Study Area ............................................................................................................................. 51.2.3. Studies Performed ................................................................................................................. 71.2.4. Studies Excluded ................................................................................................................... 8

1.3. Report Overview ............................................................................................................................ 82. Criteria, System Data, and Study Assumptions ............................................................................... 8

2.1. Criteria, Standards, and Requirements ......................................................................................... 82.1.1. AESO Transmission Reliability Criteria ................................................................................. 82.1.2. AESO Operating Policies and Procedures (OPPs) and Authoritative Documents (ADs) ..... 9

2.2. Load and Generation Assumptions ............................................................................................. 102.2.1. Load Assumptions ............................................................................................................... 102.2.2. Generation Assumptions ..................................................................................................... 102.2.3. Intertie Flow Assumptions ................................................................................................... 11

2.3. System Projects ........................................................................................................................... 122.4. Customer Connection Projects .................................................................................................... 122.5. Facility Ratings and Shunt Elements ........................................................................................... 122.6. Dynamic Data and Assumptions ................................................................................................. 152.7. Protection Fault Clearing Times .................................................................................................. 162.8. Voltage Profile Assumptions ....................................................................................................... 16

3. Study Methodology ........................................................................................................................... 163.1. Study Objectives .......................................................................................................................... 163.2. Study Scenarios .......................................................................................................................... 173.3. Connection Studies Carried Out .................................................................................................. 173.4. Load Flow Analysis ...................................................................................................................... 18

3.4.1. Contingencies Studied for Load Flow Analysis ................................................................... 183.5. Voltage Stability Analysis ............................................................................................................ 18

3.5.1. Contingencies Studied for Voltage Stability Analysis .......................................................... 193.6. Short-Circuit Analysis .................................................................................................................. 193.7. Transient Stability Analysis ......................................................................................................... 19

4. Pre-Connection System Assessment ............................................................................................. 194.1. Pre-Connection Load Flow Analysis ........................................................................................... 194.2. Pre-Connection Voltage Stability Analysis ............................................................................. 20

5. Connection Alternatives ................................................................................................................... 205.1. Overview ...................................................................................................................................... 205.2. Connection Alternatives Evaluated ............................................................................................. 20

5.2.1. Connection Alternatives Selected for Further Studies ......................................................... 215.2.2. Connection Alternatives Not Selected for Further Studies .................................................. 21


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6. Technical Analysis of the Connection Alternative ........................................................................ 216.1.1. Load Flow Analysis .............................................................................................................. 216.1.2. Voltage Stability Analysis .................................................................................................... 216.1.3. Transient Stability Analysis .................................................................................................. 226.1.4. Mitigation Measures for Identified Issues ............................................................................ 22

6.2. Conclusions and Recommendations ........................................................................................... 237. Short-Circuit Analysis ....................................................................................................................... 23

7.1. Pre-Connection ............................................................................................................................ 237.2. Post-Connection .......................................................................................................................... 23

8. Project Interdependencies ............................................................................................................... 249. Summary and Conclusion ................................................................................................................ 24

Attachments Attachment A Pre-Connection System Load Flow Plots (2016 SP and 2016 WP) Attachment B Post-Connection System Load Flow Plots (2016 SP and 2016 WP)

Figures Figure 1-1: 2016 Study Area Transmission Network ................................................................................................. 6Figure 6-1: Scenario 4: 2016 WP Post-Connection – PV Curves for 9L43 240 kV line contingency ................... 22

Tables Table 2-1: Acceptable Post-Contingency Voltage Deviations .................................................................................. 9Table 2-2: Fort McMurray (Area 25) Coincident Load Forecast ............................................................................. 10Table 2-3: Load to be studied at Wabasca 720S ...................................................................................................... 10Table 2-4: Summary of Local Generators in the Study Scenarios ......................................................................... 10Table 2-5: Summary of system projects included in the study scenarios ............................................................ 12Table 2-6: Summary of Customer Connection Assumptions ................................................................................. 12Table 2-7: Existing Transmission Line Ratings (Based on 240 kV, 144, and 72 kV nominal voltages) .............. 13Table 2-8: Transmission Line Ratings Associated with Future Projects (Based on 240 kV and 144 kV nominal voltages) ..................................................................................................................................................................... 15Table 2-9: Summary of Shunt Elements in or Important to the Study Area .......................................................... 15Table 2-10: Summary of Voltage at Key Nodes in the Study Region ..................................................................... 16Table 3-1: List of the Connection Study Scenarios ................................................................................................. 17Table 3-2: Summary of Studies Performed .............................................................................................................. 17Table 6-1: Scenario 4: 2016 WP Voltage Stability Analysis Results (Min Transfer=20.8MW) ............................. 22Table 7-1: Fault Levels – Pre-Connection 2016 WP ................................................................................................ 23Table 7-2: Fault Levels – Post-Connection 2016 WP .............................................................................................. 24Table 7-3: Fault Levels – Post-Connection 2023 WP .............................................................................................. 24


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1. Introduction

This Engineering Study Report presents the results of the study conducted to analyze the requested load addition at Wabasca 720S to the Alberta Interconnected Electric System (AIES).

1.1. Project

1.1.1. Project Overview

ATCO has received a request from a customer to provide service to their in-situ oil sands plant located at LSD 6-12-81-24 W4M. As a result, ATCO submitted a SASR to the AESO to increase the DTS for Wabasca 720S by 8.0 MW.

Wabasca 720S substation is located within the AESO Planning Sub-area 58 (Dover Sub-area), which is part of the AESO Planning Area 251 (Fort McMurray Area). The existing transformer capacity at Wabasca 720S is sufficient to facilitate the requested load increase. ATCO has requested transmission development to support the additional load.

The DTS increase and the resultant transmission development will hereafter be referred to as "the project”. The requested ISD is July 1, 2016.

1.1.2. Load Component

ATCO has provided a detailed load forecast for Wabasca 720S substation. The existing DTS contract at the Wabasca 720S substation is 22 MW and ATCO has requested an increase to 30 MW. The additional 8.0 MW represents the customer load increase; however, the total load forecast for Wabasca 720S for 2016, including all oilfield and industrial customers, is approximately 46 MW. The new project load was considered to have a power factor of 0.9. Existing load and its associated forecast growth used the historical power factor at Wabasca 720S. This resulted in a net power factor of approximately 0.96.

1.1.3. Generation Component

There is no generation component associated with this project.

1 The Base cases found on AESO’s website divide Area 25 into three sub-areas. These sub-areas are 58 (Dover), 59 (Ruth Lake), and 61 (Christina Lake). When Area 25 is referenced in this document it relates to all three of these study sub-areas in the cases (Sub-areas 58, 59, and 61).


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1.2. Study Scope

1.2.1. Study Objectives

The objectives of the study are the following:

• Evaluate the impact of the requested project load increase on the AIES.

• Identify any violations of the relevant criteria, standards or requirements of the AESO, both pre- and post-connection of the project.

• Recommend mitigation measures, if required, to enable the reliable integration of the project into the AIES.

1.2.2. Study Area

1.2.2.1. Study Area Description

The existing Wabasca 720S substation is located within the Dover Planning Sub-area 58 (Dover Sub-area), which is part of the AESO Planning Area 25 (Fort McMurray Area). The study area is Dover Sub-area 58. The Fort McMurray Area occupies the Northeast corner of Alberta. The transmission system in the area is comprised of 240 kV, 144 kV, and 72 kV transmission lines. Currently, the Fort McMurray Area connects to the AIES through four long 240 kV transmission lines. Two of these lines, 9L07 and 9L990, are part of the 240 kV path connecting Fort McMurray Area to AESO Planning Area 60 (Edmonton Area) while the third line, 9L56, is part of the path connecting Fort McMurray Area to AESO Planning Area 40 (Wabamun Area) and 9L15 which connects Fort McMurray Area with the AESO Planning Area 19 (Peace River Area). Figure 1-1 shows the pre-connection study area transmission network.


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Figure 1-1: 2016 Study Area Transmission Network


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1.2.2.2. Existing Constraints

The Northeast Region is currently managed by the ID #2011-008R, Northeast Area Transmission Constraint Management, which relates to Section 302.1 of the ISO Rules, RealTime Transmission Constraint Management.

This AESO ID specifies the Fort McMurray Area import/export cut plane limits and constrains the transfer flows in Fort McMurray Area to a maximum 730 MW out and 440 MW in. These transfer levels are based on the existing transmission network configuration and represent the system normal condition (all transmission elements in-service).

1.2.2.3. AESO Long-Term Plans

The AESO has published the AESO 2013 Long-term Plan2 (2013 LTP). It includes the following system reinforcements and customer connections in the Northeast Region up to and including 2032:

• 2 x 30 MVAr capacitor banks in the Kinosis 856S area.

• Christina Lake Area Transmission Development project which develops a transmission loop to connect the existing 240 kV and 138 kV transmission lines to support the existing and future substations in the Christina Lake area (ISD: 2015).

• Algar Area System Reinforcement project which enhances the existing 144 kV system from Ruth Lake 848S substation to McMillan 885S substation in the Fort McMurray Area and supports load growth in the area (ISD: 2015).

Other reinforcements already in-service include the 2 x 30 MVAr capacitor banks at Kettle River 2049S, 100 MVAr capacitor bank at Dover 666S, 100 MVAr capacitor bank at Whitefish 825S, 60 MVAr capacitor bank at Leismer 72S, 42 MVAr capacitor bank at Winefred 818S and the Salt Creek 977S substation, which connects the existing 9L990 240 kV line to a new 240 kV looped system to the north of Fort McMurray Area. This substation also provides system reinforcement to the 144 kV system south of Fort McMurray Area through a new 144 kV line from the new Salt Creek 977S substation to the existing Hangingstone 820S substation.

Long term development in the Fort McMurray Area includes the addition of a new 500 kV circuit from the Wabamun Area to Fort McMurray Area including a new 240/500 kV substation, Thickwood 951S, with additional VAR support. The anticipated ISD for this development is 2018-2019.

1.2.3. Studies Performed

The following studies were performed for both the pre-connection and post-connection analysis:

• Load flow analysis (Category A conditions and Category B contingencies);

• Short circuit fault studies (Category A conditions).

The following studies were performed for only the post-connection winter peak analysis:

• Voltage stability analysis (Category A conditions and Category B contingencies).

2 This document is available on the AESO website.


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1.2.4. Studies Excluded

The following studies were not performed in the connection study, based on knowledge of the study area’s transmission system:

• Load flow analysis (Category C) for both pre- and post-connection;

• Voltage stability (Category C) for both pre- and post-connection.

The following studies were not performed in the connection study because there is no generation component:

• Transient stability analysis for post-connection.

1.3. Report Overview

The Executive Summary provides a high-level summary of the report and its conclusions. Section 1 provides an introduction of the Wabasca 720S – 25 kV Breaker Addition project. Section 2 describes the Reliability Criteria, system data, and other study assumptions used in this study. Section 3 presents the study methodology used in this study. Section 4 discusses the pre-connection system assessment. Section 5 presents the connection alternatives identified. Section 6 provides a technical analysis of the post-connection system assessment for the alternatives selected for further study. Section 7 provides a short-circuit analysis for the pre- and post-connection, as well as future post-connection information. Section 8 discusses the project interdependencies. Section 9 presents the conclusions and recommendations of this study.

2. Criteria, System Data, and Study Assumptions

2.1. Criteria, Standards, and Requirements

2.1.1. AESO Transmission Reliability Criteria

The Alberta Reliability Standards and the AESO’s Transmission Planning Criteria – Basis and Assumptions (Reliability Criteria) were applied in this study to assess the system performance following Category A (i.e., all elements in service) and Category B (i.e., one element out of service) contingencies. Below is a summary of Category A and Category B system conditions.

Category A represents a normal system with no contingencies and all facilities in service. This is often referred to as the N-0 condition. The system must be able to supply all firm load and firm transfers to other areas. All equipment must operate within its applicable rating, voltages must be within their applicable ratings and the system must be stable with no cascading outages.

Category B events result in the loss of any specified single system element under specified fault conditions and normal clearing. The specified elements are a generator, a transmission circuit, a transformer or a single pole of a DC transmission line. This is often referred to as an N-


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1 event or with the most critical generator out of service, an N-G-1 event. The acceptable impact on the system is the same as Category A. Planned or controlled interruptions of electric supply to radial customers or some local network customers, connected to or supplied by the faulted element or by the affected area, may occur in certain areas without impacting the overall reliability of the interconnected transmission systems. To prepare for the next contingency, system adjustments are permitted, including curtailments of contracted firm (non-recallable reserved) transmission service electric power transfers.

The Alberta Reliability Standards include the Transmission Planning (TPL) standards that specify the desired system performance under different contingency categories with respect to the Applicable Ratings. The transmission system performance under various system conditions is defined in Appendix 1 of the TPL standards. For the purpose of applying the TPL standards to this study, the Applicable Ratings shall mean:

Seasonal continuous thermal rating of the line’s loading limits.

Highest specified loading limits for transformers.

For Category A conditions: Voltage range under normal operating condition per AESO Information Document ID# 2010-007RS.

For Category B conditions: The extreme voltage range values per Table 2-1 in the Transmission Planning Criteria – Basis and Assumptions.

Acceptable post-contingency voltage change limits for three defined post event timeframes as provided in Table 2-1, below.

Table 2-1: Acceptable Post-Contingency Voltage Deviations

Parameter Post Transient (Up to 30 sec.)

Post Auto Control (30 sec. to 5 min.)

Post Manual Control (Steady State)

Voltage Deviation from Steady State at Low Voltage

Bus ±10% ±7% ±5%

2.1.2. AESO Operating Policies and Procedures (OPPs) and Authoritative Documents (ADs)

AESO Information document ID# 2010-007RS General Operating Practices - Voltage Control, which relates to Section 304.4 of the ISO Rules, Maintaining Network Voltage, was used to establish system normal (i.e., pre-contingency) voltage profiles for the study area. The Northeast Region constraint management outlined in ID #2011-008R, Northeast Area Transmission Constraint Management, which relates to Section 302.1 of the ISO Rules, RealTime Transmission Constraint Management, will be followed to assess any criteria violations identified as a result of the connection studies. This document was reviewed prior to the study start.


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2.2. Load and Generation Assumptions

The forecast used for this connection assessment is based on the AESO’s 2012 Long-term Outlook (LTOU). As part of its planning responsibilities, the AESO updates its corporate forecasts routinely to ensure they reflect the latest economic projects, factors and timing. While the AESO has updated its regional forecasts since the connection studies were performed, the use of the current AESO forecasts (2014 Long-term Outlook) for the region would not materially alter the connection study results or affect its conclusions.

2.2.1. Load Assumptions

The Fort McMurray regional load forecast used for this connection study is reflected in Table 2-2.

Table 2-2: Fort McMurray (Area 25) Coincident Load Forecast

Area Name 2016 SP (MW)

2016 WP (MW)

25 Fort McMurray 2199 2564 AIL Total w/o Losses 10931 12551

Table 2-3 provides the load to be studied at Wabasca 720S for the study years.

Table 2-3: Load to be studied at Wabasca 720S

Facility Name 2016 SP Pre-connection

(MW)

2016 WP Pre-connection

(MW)

2016 SP Post-connection

(MW)

2016 WP Post-connection

(MW) Wabasca 720S 22 22 47 47

2.2.2. Generation Assumptions

The generation within the Northeast Region contains natural gas-fired generation from industrial sites in the Fort Saskatchewan, Fort McMurray and Cold Lake areas, and biomass generation in the Athabasca area. The generation modeled in the study scenarios are shown in Table 2-4.

Table 2-4: Summary of Local Generators in the Study Scenarios

Element Name

PSS/E bus # Unit ID PSS/E bus

Name Pmax (MW)

Generation Level Modeled in the Study Scenarios

(MW)

2016 SP 2016 WP

Kearl 1 1695 ST KEARL13C 86 59.6 71.4 ConklinGT1/GT2

2405 1 CONKLIN2 82.5 68.2 82.5 3405 2 CONKLIN4 79.8 69.5 79.8 16690 G1 MEGCHR02 93.9 75.8 93.9

91TG 5720 3273 G7 FIREBAG7 86.8 63 73.6


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Element Name

PSS/E bus # Unit ID PSS/E bus

Name Pmax (MW)

Generation Level Modeled in the Study Scenarios

(MW)

2016 SP 2016 WP

MuskegG1/G2

10236 1 MUSKEG4 101 70.4 101 12236 2 MUSKEG6 101 70.4 101

LongLake

13249 G1 LNGLKCG2 80 66.9 79.4 12249 G2 LNGLKCG1 80 66.9 79.4 11241 G3 LONGLK11 11.5 9.1 10.8 11241 G4 LONGLK11 11.5 9.1 10.8

Suncor 16218 G1 SUNC_G19 34.4 28 32.7

Millennium3/4/5/6

16219 G3 MIL_G3 68.8 56 65.4 18223 G4 TAR GN 2 81 63 73.6 18208 G5 MIL_G5 9 130.5 97.9 114.5 19208 G6 MIL_G6 9 130.5 97.9 114.5

SyncrudeUE 1G11/G12

17233 11 SYNC_UE4 22 11.5 13.8

16233 12 SYNC_UE5 86 57.5 68.9 Aurora(Syncrude)

18206 2 AUR_GTG2 100 63.6 78 18207 1 AUR_GTG1 100 65.2 78

SyncrudeG1 6G20/21

19209 G1 SYNC_G19 53 34.5 41.3 18209 G2 SYNC_G29 53 34.5 41.3 18218 G2 SUNC G29 34.4 28 32.7 17209 G3 SYNC_G39 28.8 20 23 17210 G4 SYNC_G49 53 34.5 41.3 18210 G5 SYNC_G59 28.8 20 23 19210 G6 SYNC_G69 67.5 42.2 50.5

MacKay1 18274 1 MACKAY2 185 148 175.7

EDD(Suncor)

16297 G4 EDD716X 95 70 81.8 17297 G3 EDD717X 95 70 81.8 19297 1 EDD718X 85 63 73.6 18297 1 EDD719X 85 63 73.6

Horup19264 5 HORUP6 15.9 14.9 15.9 18264 G1 HORUP7 84.9 78.2 84.9

GENCO70154 54 GENCOG54 15.9 10.6 70157 57 GENCOG57 15.9 12 14.2 70158 58 GENCOG58 15.9 8 9.5

Total Study Area Generation 3190.2 1771.0 2162.1

2.2.3. Intertie Flow Assumptions

As per the AESO study reference information for this area, the interties are considered too far away to impact the studies.


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2.3. System Projects

The transmission system projects that are included in the 2016 SP and 2016 WP scenarios for this connection study are shown in Table 2-5.

Table 2-5: Summary of system projects included in the study scenarios

ID Project Name ISD Included in the Study Scenarios

P1128 Fort McMurray Additional Reactive Support at Kinosis 2015 2016 SP & 2016 WP

P1106 Fort McMurray Additional Reactive Support at Kettle River 2014 2016 SP & 2016 WP

2.4. Customer Connection Projects

Table 2-6 presents a summary of the customer connection projects which were expected to be in-service within the timeframe of this project development and are included in the study scenarios.

Table 2-6: Summary of Customer Connection Assumptions

ID Project Name Included in the Study Scenarios

1104 AOC Dover West Leduc Insitu Bitumen Extraction Facility 2016 SP & 2016 WP

1122 ATCO Stat Oil -Egg Lake SAGD Facility* 2016 SP & 2016 WP

1214 ATCO AOC Hangingstone - Willow Lake Substation 2016 SP & 2016 WP

1225 ATCO JACOS – Sweet Heart Lake 2016 SP & 2016 WP

1258 Fortis Alberta Grist Lake (Pike) Substation 2016 SP & 2016 WP

1287 Fortis Alberta CNRL - Edwards Lake Substation 2016 SP & 2016 WP

1309 ATCO Cheecham POD (Meadow Creek 2081S) 2016 SP & 2016 WP

1348 Fort Hills Switching Station Addition 2016 SP & 2016 WP

1404 Cenovus Narrows Lake Substation (Boreal) 2016 SP & 2016 WP

948 MacKay Operating Corp. AMR02 Substation 2016 SP & 2016 WP

776 ATCO - Laricina Saleski SAGD New POD 2016 SP & 2016 WP

1106 Kettle River – Bohn 2016 SP & 2016 WP

1128 Conoco Philips Phase II and III 2016 SP & 2016 WP

1067 Dover north – south* 2016 SP & 2016 WP

* This project has since been cancelled. Cancellation of this project has no material impact on the recommendations provided in this report regarding the connection of the project.

2.5. Facility Ratings and Shunt Elements

Table 2-7 provides the ratings of the existing transmission lines in the Northeast Region.


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Table 2-7: Existing Transmission Line Ratings (Based on 240 kV, 144, and 72 kV nominal voltages)

Line From To Voltage (kV)

Summer (MVA)

Winter (MVA)

DML Sync_D Syncru_B 72 75 75

DML Sync_D Sync_UE 72 75 75

DML Syncru_A Sync_UE 72 75 75

Bus Tie Syncru_B Syncru_A 72 1000 1000

7L02 McMillan 885S Crow 860S 144 114 145

7L15 Long Lake 841S Kinosis 856S 144 146 187

7L05 Kettle River 2049S Bohn 931S 144 99 99

7L104 Kinosis 856S Quigley 989s 144 164 210

7L167 Quigley 989s Engstrom 2060S 144 164 210

7L183 Kinosis 856S Engstrom 2060S 144 259 299

7L36 Willow Lake 2009S Hanging Stone 820S 144 114 145

7L194 Willow Lake 2009S Algar 875S 144 99 99

7L155 Gregorie 883S Willow Lake 2009S 144 99 99

7L38 Algar 875S Horse River 917S 144 99 99

7LA121 Mariana 833S Mariana Tap 144 114 145

7L47 Ruth Lake 848S Parsons Creek 718S 144 99 99

7L71 Ruth Lake 848S Parsons Creek 718S 144 99 99

7L135 Hanging Stone 820S Salt Creek 977S 144 149 149

7L97 Hanging Stone 820S Tower Road 933S 144 114 145

7LA97 Halfway 2014S 7L97 Tap 144 114 145

7L165 Parsons Creek 718S Tower Road 933S 144 114 145

7L125 Livock 939S Germain 950S 144 99 99

7L121 Crow 860S Horse River 917S 144 114 145

29PL9-1 Ruth Lake 848S Millennium 29EDD-1 240 485 590

29PL9-2 Ruth Lake 848S Millennium 29EDD-1 240 485 590

29PL9-3 Millennium 29EDD-1 EDD34 29EDD-3 240 400 400

29PL9-4 Millennium 29EDD-1 EDD34 29EDD-3 240 400 400

75PHL-903 Hormin 7501 Horup 7502 240 408 523

75PHL-904 Hormin 7501 Horup 7502 240 408 523

75PKL-901 Hormin 7501 Joslyn 849S 240 753 831

75PKL-902 Hormin 7501 Joslyn 849S 240 753 831

957L Leismer 72S Christina Lake 723S 240 594 713

7L114 Leismer 72S Waddell 907S 144 164 210

7LA114 Chard 958S 7L114 Tap 144 99 99

9L01 Dover 888S Ruth Lake 848S 240 549 701

9L07 McMillan 885S Dover 888S 240 549 701


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Summer (MVA)

Winter (MVA)

9L08 Dover 888S Joslyn 849S 240 753 831

9L09 Dover 888S Joslyn 849S 240 753 831

9L43 Dover 888S Mackay 874S 240 549 701

9L22 Heart Lake 898S Whitefish Lake 825S 240 498 498

789L Hear Lake 898S Winefred 818S 144 256 256

788L Hear Lake 898S Lac La Biche 157S 144 284 284

9L55 McMillan 885S Heart Lake 898S 240 549 701

9L56 Wabasca 720S Brintnell 876S 240 488 624

9L56 Wabasca 720S Mitsue 732S 240 332 332

9L74 Dover 888S Birchwood Creek 960S 240 416 526

9L74 Birchwood Creek 960S Livock 939S 240 488 624

9L10 Livock 939S Brintnell 876S 240 488 624

9L19 Birchwood Creek 960S AMR02 (AOSC) 937S 240 433 524

9L28 Birchwood Creek 960S AMR02 (AOSC) 937S 240 433 524

9L39 Green Stocking 925S Black Fly 939S 240 549 701

9L77 Green Stocking 925S Black Fly 939S 240 549 701

9L69 Black Fly 939S McClelland 957S 240 753 831

9L84 Black Fly 939S Salt Creek 977S 240 753 831

9L23 Ruth Lake 848S Salt Creek 977S 240 519 663

9L85 Kinosis 856S Salt Creek 977S 240 519 663

9L45 Kettle River 2049S Kinosis 856S 240 519 663

9L990 Kettle River 2049S Leismer 72S 240 519 663

9L15 Wesley Creek 834S Brintnell 876S 240 549 701

9L58 Dover 888S Ruth Lake 848S 240 416 526

9L66 Muskeg River 847S Joslyn 849S 240 376 423

9L930 Leismer 72S Whitefish Lake 825S 240 498 498

9LJH1 Muskeg River 847S Jackpine 920S 240 460 556

9LJH2 Muskeg River 847S Jackpine 920S 240 460 556

RL1 Ruth Lake 848S Sync D05 240 332 332

RL2 Ruth Lake 848S Sync D05 240 332 332

AL-1 Sync D05 Aurora G01 240 312 356

AL-2 Sync D05 Aurora G01 240 312 356

9L32 Joslyn Creek 849S McClelland 957S 240 753 831

L9900 Kearl Main 9900S Bitumont 941S 240 376 480


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Table 2-8 provides the ratings of the transmission lines associated with future projects in the Northeast Region.

Table 2-8: Transmission Line Ratings Associated with Future Projects (Based on 240 kV and 144 kV nominal voltages)


Summer (MVA)

Winter (MVA)

7L142 Laricina Saleski 901S Livock 939S 144 165 211 7L170 Dawes 2011S Algar 875S 144 129 157 7L194 Dawes 2011S Willow Lake 2009S 144 114 145 7L147 Dawes 2011S Sweetheart Lake 2032S 144 149 149 9L89 McMillan 885S Dawes 2011S 240 549 701 9L07 Dawes 2011S Thickwood 240 549 701 9L30 Dover 888S Thickwood 240 416 526

9L112 Dover 888S Thickwood 240 549 701 9L58 Ruth Lake 848S Thickwood 240 549 701 9L32 Joslyn 849S Secord 2005S 240 753 831

9L101 Secord 2005S McClelland 957S 240 753 831 9L929 Leismer 72S Edwards Lake 189S 240 519 663 9L930 Edwards Lake 189S Heart Lake 898S 240 519 663 9L81 Heart Lake 898S Whitefish 825S 240 498 498 9L08 Dover 888S Ells River 2079S 240 753 831 9L76 Ells River 2079S Joslyn 849S 240 753 831

Table 2-9 provides the study area shunt elements.

Table 2-9: Summary of Shunt Elements in or Important to the Study Area

Bus Number Bus Name kV Blk 1

Steps Blk 1 Bstep (MVAr)

Blk 2 Steps

Blk 2 Bstep (MVAr)

Blk 3 Steps

Blk 3 Bstep (MVAr)

666 DOVER 240 1 -40 1 100 0 0 1259 HORUP3 34 1 21.11 0 0 0 0 1264 HORUP2 34 1 10.56 0 0 0 0 1265 HORUP4 34 1 21.11 0 0 0 0 1268 HORUP5 34 1 14.57 0 0 0 0 1290 HORSERV7 138 2 13.78 0 0 0 0 18251 HORMIN9 34 1 21.11 0 0 0 0 19251 HORMIN8 34 1 21.11 0 0 0 0

2.6. Dynamic Data and Assumptions

This section is not applicable as dynamic study is not required.


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2.7. Protection Fault Clearing Times


2.8. Voltage Profile Assumptions

The desired range bus voltages, specified in the AESO Information Document ID# 2010-007RS General Practice for Voltage Control, were used for the area key busses voltage profiling in the study area under system normal conditions (i.e. pre-contingency).

The key bus voltages for the study area for the project are shown in Table 2-10.

Table 2-10: Summary of Voltage at Key Nodes in the Study Region

Substation

ID# 2010-007RS Voltage in the Study Scenarios N-0 (kV)

Nominal Voltage

(kV)

Minimum Operating Limit (kV)

Desired Range (kV)

Maximum Operating Limit (kV)

Pre-connection Post-connection

Scenario 1 2016 SP

Scenario 2 2016 WP

Scenario 3 2016 SP

Scenario 4 2016 WP

Dover 888S 240 263 264 – 271 275 269.2 267.5 269.1 267.4

Ruth Lake 848S 240 248 263 – 269 275 264.0 264.0 264.0 264.0

McMillian885S 240 256 263 – 272 275 270.6 270.1 270.7 270.2

Wesley Creek 834S 240 257 257 – 268 275 267.5 264.3 267.0 264.0

Mitsue 732S 240 252 256 – 269 275 262.5 262.1 261.6 261.3

Wabasca720S 240 254 259-269 275 266.4 264.1 266.5 262.5

3. Study Methodology

All the studies were completed using PTI PSS/E version 33.

3.1. Study Objectives

The objectives of the study are the following:

• Evaluate the impact of the requested project load increase on the AIES.

• Identify any violations of the relevant criteria, standards or requirements of the AESO, both pre- and post-connection of the project.


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• Recommend mitigation measures, if required, to enable the reliable integration of the project into the AIES.

3.2. Study Scenarios

The requested ISD for the load addition at Wabasca 720S is July 2016. Hence, the study was conducted for the 2016 SP and 2016 WP. The study scenarios were derived from the published AESO’s 2013 Planning Base Case Suite and related Auxiliary Data Files representing the summer peak and winter peak conditions of 2016. The load and generation dispatches for 2016 year were provided by the AESO to adjust the load and generation in the base cases.

The study scenarios are shown in Table 3-1. This table lists the scenarios and load development considered in this study. The new project load was considered to have a power factor of 0.9. Existing load and its associated forecast growth used the historical power factor at Wabasca 720S. This resulted in a net power factor of approximately 0.96.

Table 3-1: List of the Connection Study Scenarios

Scenario No. Study Scenario Wabasca 720S Load (MW)

Existing System (Pre-connection)

1 2016 SP 22

2 2016 WP 22

Post-connection System

3 2016 SP 47

4 2016 WP 47

3.3. Connection Studies Carried Out

The following studies were carried out for this connection study, as summarized in Table 3-2:

Table 3-2: Summary of Studies Performed

Scenario(s) Studied Studies Performed Contingencies Included

Pre-connection Post-connection

1 and 2 3 and 4 Load Flow Category A and B

4 Voltage Stability Category A and B

2 4 and 2023 WP Short Circuit Category A


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3.4. Load Flow Analysis

Load flow analysis was conducted on all study scenarios to identify any thermal overloads or transmission voltage violations, as per the Reliability Criteria and the specified limits in Table 2-1. The purpose of the load flow analysis is to quantify any incremental violations in the study area after the project is connected.

Point of Delivery (POD) low voltage bus deviations were also assessed by first locking all tap changers and area capacitors to identify any post transient voltage deviations above 10%. Tap changers were then allowed to move while capacitors remained locked to determine if any voltage deviations above 7% were found in the area. Once all taps and capacitor controls were allowed to adjust, voltage deviations above 5%, if any, were reported for both the pre-connection and post-connection networks.

3.4.1. Contingencies Studied for Load Flow Analysis

The Dover Sub-area was monitored for voltage and thermal violations during contingency analysis. The contingencies studied include all lines and transformers in the study area, including the following tie lines to the surrounding areas:

9L15 (Brintnell 876S to Wesley Creek 834S); 9L56 (Wabasca 720S to Mitsue 732S); 9L01 (Dover 888S to Ruth Lake 848S); 9L58 (Dover 888S to Ruth Lake 848S); 9L07 (Dover 888S to Dawes 2011S); 9L32 (Joslyn 849S to Secord 2005S); 9L66 (Joslyn 849S to Muskeg River 847S).

3.5. Voltage Stability Analysis

The objective of the voltage stability analysis is to determine the ability of the network to maintain voltage stability at all the busses in the system under normal and abnormal system conditions. The Power-Voltage (PV) curve is a representation of voltage change as a result of increased power transfer between two systems. The reported incremental transfers will be to the collapse point. As per the AESO requirements, no assessment based upon other criteria such as minimum voltage will be made at the PV minimum transfer.

The voltage stability analysis was performed according to the Western Electricity Coordinating Council (WECC) Voltage Stability Assessment Methodology. WECC voltage stability criteria states, for load areas, post-transient voltage stability is required for the area modeled at a minimum of 105% of the reference load level for system normal conditions (Category A) and for single contingencies (Category B). For this standard, the reference load level is the maximum established planned load.

Typically, voltage stability analysis is carried out assuming the worst case scenarios in terms of loading. As per Table 6-1, only Scenario 4 (post-connection 2016 WP) was considered in the analysis; however, if margin problems had been encountered, Scenario 2 (pre-connection 2016 WP) would have had to be studied as well.


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The Voltage Stability analysis was performed by increasing load in the Dover Sub-area and increasing the generation in the following AESO planning areas:

• Calgary (Area 6).

• Northeast Region Generators (Area 33)

• Central and Edmonton Region Generators (Areas 30, 35, 40, and 60).

• South Region Generation (Areas 43, 53, 54, 55, and 57).

When increasing load and generation, the load increase power factor was set to 0.9 and no limits were selected for the generation sources. In the voltage stability analysis, all transformer tap changers and discrete capacitors were locked and SVCs were allowed to adjust.

3.5.1. Contingencies Studied for Voltage Stability Analysis

Voltage stability analysis was performed for all Category B contingencies in the study area for the 2016 WP post-connection scenario to determine the system voltage stability margin in this winter peaking area.

3.6. Short-Circuit Analysis

The short-circuit analysis was performed prior to and following the project connection under the 2016 WP scenario, as well as for the future ten-year system using the post-connection 2023 WP study scenario. The short circuit analysis includes three-phase and single-line-to-ground faults. Fault levels, in the form of currents in kilo amperes and per unit positive and zero sequence impedances, are provided for all buses at Wabasca 720S and adjacent (directly-connected) substations with all area generators on.

3.7. Transient Stability Analysis


4. Pre-Connection System Assessment

4.1. Pre-Connection Load Flow Analysis

No transmission criteria violations were found in the pre-connection scenarios studied for the study area (Dover Sub-area). Please refer to Attachment A for pre-connection system load flow plots for the study area.

4.1.1.1. Scenario 1: 2016 Summer Peak (2016 SP)

No thermal overloads, voltage or POD bus voltage deviation violations were found for any Category A or B condition within the study area.


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4.1.1.2. Scenario 2: 2016 Winter Peak (2016 WP)


4.2. Pre-Connection Voltage Stability Analysis

This section is not applicable as pre-connection voltage stability analysis is not required.

5. Connection Alternatives

5.1. Overview

ATCO, the Distribution Facility Owner (DFO) in the area, considered using a distribution-only solution to support the load increase requested by a customer. This alternative did not meet the DFO's distribution planning guidelines, and was ruled out. Two transmission alternatives were identified for this project:

Alternative 1: Modify the existing Wabasca 720S substation

Alternative 2: Add a new POD substation

5.2. Connection Alternatives Evaluated

Two transmission alternatives were identified that could support the load increase. A brief description of the developments associated with each alternative is provided below3. Alternative 1: Modify the Wabasca 720S substation This alternative involves modifying the Wabasca 720S substation, including:

Add a new 25 kV breaker. Alternative 2: Add a new POD substation: This alternative involves building a new POD substation connected to the existing transmission line 9L56 via an in-and-out connection configuration. The transmission development includes:

Add a new 240-25 kV POD at NE-11-81-24-W4M; Add one 30/40/50 MVA 240-25 kV LTC transformer; Add three 240 kV breakers and associated disconnect switches;

3 These alternatives reflect more up to date engineering design than the alternatives identified in the ATCO Electric Distribution Deficiency Report (DDR), AESO Connection Project #1491 Wabasca 720S Substation Distribution Deficiency Report, filed under a separate cover.


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Add approximately 5 km of new double circuit 240 kV transmission line.

5.2.1. Connection Alternatives Selected for Further Studies

Alternative 1 was selected for further study.

5.2.2. Connection Alternatives Not Selected for Further Studies

Alternative 2 was not selected for further study. Alternative 2 involves more transmission system development compared to Alternative 1.

6. Technical Analysis of the Connection Alternative

No transmission criteria violations were found in the post-connection scenarios studied for the study area (Dover Sub-area). Please refer to Attachment B for post-connection system load flow plots for the study area. Also, no voltage stability margin problems were found in the study area for this connection project.

6.1.1. Load Flow Analysis

6.1.1.1. Scenario 3: 2016 Summer Peak (2016 SP)




6.1.2. Voltage Stability Analysis

The voltage stability analysis was completed for the post-connection winter peak scenario (2016 WP). The PV margins are shown in tabular form for the five (5) transmission contingencies in Dover Sub-area that have the lowest PV transfer margin. The PV graph for the worst contingency is also provided.


Figure 6-1 shows the PV graph for the worst contingency in this scenario, 9L43 from Dover 888S to MacKay 874S.


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With the project load in this winter peak scenario, the reference load level for the study area (Dover Sub-area 58) is 415.4 MW. The minimum incremental load transfer for the Category B contingencies is 5.0% or 20.8 MW (0.05 x 415.1 MW = 20.8 MW) to meet the voltage stability criteria. All contingencies meet the minimum criteria. Please refer to Table 6-1.

Figure 6-1: Scenario 4: 2016 WP Post-Connection – PV Curves for 9L43 240 kV line contingency

Table 6-1: Scenario 4: 2016 WP Voltage Stability Analysis Results (Min Transfer=20.8MW)

Contingency

From To

Maximum incremental

transfer (MW)

Meets 105% transfer criteria?

N-0 System Normal 455.0 Yes 9L43 Dover 888S MacKay 874S 332.5 Yes 9L10 Brintnell 876S Livock 939S 341.3 Yes Livock 939S 240 kV Phase Shifter Transformer* 341.3 Yes 9L56 segment Wabasca 720S Mitsue 732S 355.6 Yes 9L15 Wesley Creek 834S Brintnell 876S 372.5 Yes

* The Livock 939 PST tap is locked on the neutral position in the voltage stability analysis.

6.1.3. Transient Stability Analysis


6.1.4. Mitigation Measures for Identified Issues

No transmission criteria violations occurred in the study scenarios, so no mitigation measures are required.


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6.2. Conclusions and Recommendations

There were no transmission criteria violations found within the study area for this requested connection project. Therefore, Alternative 1 is the recommended alternative.

7. Short-Circuit Analysis

The short circuit analysis was performed for the 2016 WP scenarios (pre- and post-connection) with all generation units in-service. Also, the 2023 WP study scenario is used for the long-term short circuit outlook analysis. Single phase and three phase fault currents were calculated and provided in the following tables. The impedances are given in p.u. and were calculated using base voltage and 100 MVA.

Short circuit levels4 at the existing substations will not change significantly as this is a breaker addition at an existing facility for a load addition. Short circuit levels will continue to increase as generation and transmission facilities are added to the grid.

7.1. Pre-Connection

Table 7-1provides the pre-connection 2016 WP short-circuit levels.

Table 7-1: Fault Levels – Pre-Connection 2016 WP

Substation Base

Voltage

(kV)

Pre-fault Voltage

(kV)

3- Fault (kA)

Positive Sequence Thevenin Source

Impedance (R1+jX1) (p.u.)

1- Fault (kA)

Zero Sequence Thevenin Source


Wabasca 720S 240 261.37 4.64 0.013638+j0.054732 5.18 0.001987+j0.039736

25 25.78 7.78 0.038555+j0.303625 8.24 0.001655+j0.255997

Mitsue 732S 240 260.74 5.76 0.012124+j0.043728 5.92 0.004025+j0.042056

Brintnell 876S 240 261.44 5.01 0.0124+j0.050846 5.32 0.002433+j0.043841

7.2. Post-Connection

Table 7-2 and Table 7-3 provide the post-connection 2016 WP and 2023 WP short-circuit levels, respectively.

4 Short-circuit current studies were based on modeling information provided to the AESO by third parties. The authenticity of the modeling information has not been validated. Fault levels could change as a result of system developments, new customer connections, or additional generation in the area. It is recommended that these changes be monitored and fault levels reviewed to ensure that the fault levels are within equipment operating limits. The information provided in this study should not be used as the sole source of information for electrical equipment specifications or for the design of safety-grounding systems.


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Table 7-2: Fault Levels – Post-Connection 2016 WP

Substation Base

Voltage

(kV)

Pre-fault Voltage

(kV)

3- Fault (kA)



1- Fault (kA)



Wabasca 720S 240 261.60 4.64 0.014283+j0.054699 5.18 0.001985+j0.039721

25 25.80 7.94 0.054899+j0.294994 8.37 0.001726+j0.257416

Mitsue 732S 240 260.80 5.76 0.012307+j0.04371 5.92 0.004025+j0.042055

Brintnell 876S 240 262.48 4.98 0.012947+j0.051227 5.31 0.002433+j0.043838

Table 7-3: Fault Levels – Post-Connection 2023 WP

Substation Base

Voltage

(kV)

Pre-fault Voltage

(kV)

3- Fault (kA)



1- Fault (kA)



Wabasca 720S 240 260.02 5.92 0.009701+j0.042914 6.20 0.002212+j0.038524

25 25.98 8.11 0.038656+j0.293478 8.50 0.001895+j0.255899

Mitsue 732S 240 259.95 6.68 0.009551+j0.037795 6.48 0.00421+j0.042759

Brintnell 876S 240 259.91 7.11 0.007743+j0.035794 7.17 0.002572+j0.036011

8. Project Interdependencies

No project interdependencies were identified.

9. Summary and Conclusion

ATCO has received a request from a customer to provide service to their in-situ oil sands plant located at LSD 6-12-81-24 W4M. As a result, a new SASR was submitted to the AESO to increase the DTS for Wabasca 720S from 22 MW to 30 MW. Considering this 8.0 MW load increase along with other oilfield and industrial customers in the area, the total load forecast for Wabasca 720S for 2016 is approximately 46 MW. The requested ISD for this project is July 1, 2016.

Wabasca 720S substation is within the AESO Planning Sub-area 58 (Dover Sub-area), which is part of the AESO Planning Area 25 (Fort McMurray Area). The existing transformer capacity at Wabasca 720S is sufficient to facilitate the requested load increase. ATCO has requested transmission development to support the additional load.

Two transmission alternatives were identified for this project:


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Alternative 1: Modify the existing Wabasca 720S substation by adding a new 25 kV breaker at Wabasca 720S substation;

Alternative 2: Add a new 240-25 kV POD substation.

Alternative 2 was not selected for further study as it involves more transmission system development compared to Alternative 1. Alternative 1 was studied to accommodate the project load addition.

Load flow analysis was conducted for the pre- and post-connections 2016 WP and 2016 SP conditions to assess the impact of the requested Wabasca 720S substation modification on the transmission system. Voltage stability analysis was performed for the post-connection 2016 WP condition. Lastly, short circuit analysis was performed for the pre- and post-connection 2016 WP conditions and also for the post-connection 2023 WP condition to determine the short circuit levels in the vicinity of the Wabasca 720S substation.

The results of the above studies show that there were no transmission thermal overloads, voltage criteria violations or voltage stability violations found with this project addition for the scenarios analyzed. Based upon the study results, Alternative 1 is the recommended alternative.

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ATTACHMENT A Pre-Connection System Load Flow Plots (2016

SP and 2016 WP)

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System Load Flow Results Load Flow Diagrams The pre-connection load flow diagrams for Category A and selected Category B contingencies are provided in this section. The following table presents the list of the load flow diagrams.

Table B-1: List of pre-connection load flow diagrams

Scenario Load flow diagram Page number

2016 SP

N-0, System Normal Condition A-3 N-1, Loss of 9L15 A-4 N-1, Loss of 9L10 A-5 N-1, Loss of 9L40 A-6 N-1, Loss of 9L913 A-7

2016 WP

N-0, System Normal Condition A-8 N-1, Loss of 9L15 A-9 N-1, Loss of 9L10 A-10 N-1, Loss of 9L40 A-11 N-1, Loss of 9L913 A-12

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Christina Lake Area

High Prairie Area


Peace River Area

Dover 888S

1.1264.6

9L15

9L56-1

9L56-2



9L58

9L58

1.1268.9


-1.2

-37.

0

1.2

1605THICKWD2

29

48.9

24.5

SW

-121.0

1.1264.1

6.4

1.1270.032

.9

-34.

3

-32.

8

10.7

1260LOU CR.4

1.1258.9 1.1

260.5

-188

.2

191.

8

-41.

6

138N BARRH4

30.5

204MCMILLA4

-43.8

75.0

44.1-85.9

22.0

-22.

0

-6.5

7.8

-0.0

-0.0

-0.0

1.025.9

19226WABASCA9

0.0

1.025.8

18226WABASCA8

1.136.4

SW

86.1

10605THICKWD4

Page A- 7

SW

59.6

-47.

9

-27.

6-2

9.4

20.0

-16.

3

1.1265.7

63.5

-63.

468

.3 1.1264.6

1.1264.3

-124

.2

SW

-0.0

-68.

1

1.1262.187

.0

666DOVER

1.1266.8

40.4

-30.

412

.6

-20.

4

10.4

20.4

-22.

6

1.1266.8 -5

.1

9.9

5.0

1.1266.8

9.9

5.0

80.1

13.2

-79.

8

765STONE_01

1.1263.6-8

1.4

-44.

1

81.4

41.5

1288LIVOCK01

1228MITS E.4

-34.

7

1800ER_01

-5.1

-9.9

68.1

-9.4

-5.0

9.5

3.3

-10.2 9.6

-9.9

18.2

67.4

-43.

5

-66.

6

-20.

6

-86.

2

-27.6

-12.8

-27.

6

-12.

8

16.3

1.0142.7

20.7

75.6H

175.7

-18.11.1270.4

-165

.3

-59.

3

74.6

1.0142.8

-84.6

1.1265.1

1.1267.8

1.1264.4

1280BRINT02

1.0143.3

1669AMRBUS01

1.1264.0

18288LIVOCK03

1008SALE01

1626AMRBUS04

1670BWC01

-40.

3

1200RUTH LK4

DoverArea

1006GERMAIN1

-45.

1

9L409L913

9L30

9L07

9L07

9L68

Livock 939S

9L89

SVC

9L019L95

9L82

9L28

9L19

9L57

9L10

PST

1602LIVOCKPS

1274MACKAY

9L08 9L43

Ruth Lake Area

1655DAWES240

CATEGORY A, N-G-02016 WP WITHOUT PROJECT

THU, NOV 27 2014 15:09

Brintnell 876S

1080WESLY C4

Christina Lake Area

High Prairie Area


Peace River Area

Dover 888S

1.1264.1

9L15

9L56-1

9L56-2



9L58

9L58

1.1267.5

Bus - Voltage (kV/pu)Branch - MW/MvarEquipment - MW/Mvar100.0%Rate BkV: >0.000 <=34.500 <=72.000 <=144.000 <=240.000

43.9

-43.

6

-43.

7

1605THICKWD2

29

71.8

35.9

SW

-241.2

1.1263.6

14.4

1.1270.1-5

.3

-13.

8

5.3

-10.

3

1260LOU CR.4

1.1258.8 1.1

260.4

-99.

6

100.

7

-52.

7

116.

2

-42.

9

-113

.8

138N BARRH4

13.9

26.9

204MCMILLA4

-43.7

51.3

43.9-62.9

22.6

-22.

6

-7.4

8.8

-0.0

-0.0

-0.0

1.026.1

19226WABASCA9

0.0

1.025.7

18226WABASCA8

1.136.4

SW

85.7

10605THICKWD4

Page A- 8

SW

64.6

-47.

7

-44.

7-2

3.8

16.2

-33.

7

1.1261.3

110.

9-1

10.5

48.9 1.1

258.5

1.1261.9

-123

.0

SW

-0.0

-48.

7

1.1258.913

5.4

666DOVER

1.1264.3

21.0

-47.

730

.4

-1.0

28.5

1.0

-40.

3

1.1264.3 -5

.1

9.9

5.0

1.1264.3

9.9

5.0

79.2

12.6

-78.

9

765STONE_01

1.1262.3-8

1.4

-44.

2

81.4

41.6

1288LIVOCK01

1228MITS E.4

-33.

9

1800ER_01

-5.1

-9.9

48.7

-9.4

-5.0

9.5

3.3

-10.2 9.6

-9.9

18.2

-133

.6

-27.6

-13.0

-27.

6

-12.

9

33.7

1.0140.3

15.0

75.6H

175.7

-18.11.1269.4

-165

.3

-64.

3

65.2

1.0140.4

-75.2

1.1260.1

1.1266.5

1.1263.1

1280BRINT02

1.0140.9

1669AMRBUS01

1.1263.2

18288LIVOCK03

1008SALE01

1626AMRBUS04

1670BWC01

-20.

9

1200RUTH LK4

DoverArea

1006GERMAIN1

-33.

4

9L409L913

9L30

9L07

9L07

9L68

Livock 939S

9L89

SVC

9L019L95

9L82

9L28

9L19

9L57

9L10

PST

1602LIVOCKPS

1274MACKAY

9L08 9L43

Ruth Lake Area

1655DAWES240

CATEGORY B, LOSS OF 9L152016 WP WITHOUT PROJECT

THU, NOV 27 2014 15:10

Brintnell 876S

1080WESLY C4

Christina Lake Area

High Prairie Area


Peace River Area

Dover 888S

1.1258.5

9L15

9L56-1

9L56-2



9L58

9L58

1.1266.2


35.9

-44.

5

-35.

7

1605THICKWD2

29

71.8

35.9

SW

-241.2

1.1263.6

15.4

1.1269.22.

3

-13.

8

-2.3

-10.

2

1260LOU CR.4

1.1257.7 1.1

259.0

-128

.1

129.

8

-41.

1

122.

5

-35.

5

-119

.8

138N BARRH4

8.4

19.4

204MCMILLA4

-47.2

44.4

47.4-56.1

22.6

-22.

6

-7.4

8.8

0.0

-0.0

-0.0

1.025.8

19226WABASCA9

0.0

1.025.7

18226WABASCA8

1.136.4

SW

85.7

10605THICKWD4

Page A- 9

SW

76.8

-48.

0

-10.

90.

80.

0

1.1266.5

16.4

-16.

4

1.1263.2

1.1264.2

-124

.4

SW

-0.0

1.1262.139

.3

666DOVER

1.1267.2

-27.

7

-13.

4-4

.9

47.7

-6.7

-47.

6

-5.1

1.1267.2 -5

.1

9.9

5.0

1.1267.2

9.9

5.0

76.9

13.6

-76.

7

765STONE_01

1.1263.7-8

1.4

-44.

1

81.4

41.5

1288LIVOCK01

1228MITS E.4

-35.

3

1800ER_01

-5.1

-9.9

0.0

-9.4

-5.0

9.5

3.2

-10.2 9.6

-9.9

18.2

45.6

-37.

6

-45.

2

-29.

2

-39.

1

-27.6

-12.8

-27.

6

-12.

8

1.0143.2

2.1

75.6H

175.7

-18.11.1270.2

-165

.3

-76.

4

79.9

1.0143.2

-89.3

1.1266.5

1.1268.0

1.1264.5

1280BRINT02

1.0143.7

1669AMRBUS01

1.1264.1

18288LIVOCK03

1008SALE01

1626AMRBUS04

1670BWC01

27.8

1200RUTH LK4

DoverArea

1006GERMAIN1

-29.

7

9L409L913

9L30

9L07

9L07

9L68

Livock 939S

9L89

SVC

9L019L95

9L82

9L28

9L19

9L57

9L10

PST

1602LIVOCKPS

1274MACKAY

9L08 9L43

Ruth Lake Area

1655DAWES240


THU, NOV 27 2014 15:10

Brintnell 876S

1080WESLY C4

Christina Lake Area

High Prairie Area


Peace River Area

Dover 888S

1.1263.1

9L15

9L56-1

9L56-2



9L58

9L58

1.1267.7


15.6

-36.

7

-15.

6

1605THICKWD2

29

71.8

35.9

SW

-241.2

1.1263.6

6.6

1.1269.621

.6

-21.

1

-21.

6

-2.7

1260LOU CR.4

1.1259.0 1.1

260.6

-74.

4

75.0

-48.

0

92.6

-39.

9

-91.

1

138N BARRH4

6.2

19.5

204MCMILLA4

-56.1

55.0

56.4-66.2

22.6

-22.

6

-7.4

8.8

0.0

-0.0

-0.0

1.026.0

19226WABASCA9

0.0

1.025.6

18226WABASCA8

1.136.4

SW

85.7

10605THICKWD4

Page A- 10

SW

63.9

-47.

9

-27.

1-2

2.9

12.9

-15.

3

1.1265.3

24.5

-24.

551

.3 1.1264.2

1.1263.7

-124

.1

SW

-0.0

-51.

2

1.1261.347

.4

666DOVER

1.1266.6

23.5

-29.

211

.1

-3.6 8.9

3.6

-21.

0

1.1266.6 -5

.1

9.9

5.0

1.1266.6

9.9

5.0

79.3

13.2

-79.

0

765STONE_01

1.1263.5-8

1.4

-44.

1

81.4

41.5

1288LIVOCK01

1228MITS E.4

-34.

8

1800ER_01

-5.1

-9.9

51.2

-9.4

-5.0

9.5

3.3

-10.2 9.6

-9.9

18.2

90.0

-45.

3

-88.

5

-14.

1

-47.

2

-27.6

-12.9

-27.

6

-12.

8

15.3

1.0142.5

14.2

75.6H

175.7

-18.11.1270.3

-165

.3

-63.

5

74.7

1.0142.6

-84.6

1.1264.8

1.1267.7

1.1264.3

1280BRINT02

1.0143.1

1669AMRBUS01

1.1263.9

18288LIVOCK03

1008SALE01

1626AMRBUS04

1670BWC01

-23.

4

1200RUTH LK4

DoverArea

1006GERMAIN1

-41.

1

9L409L913

9L30

9L07

9L07

9L68

Livock 939S

9L89

SVC

9L019L95

9L82

9L28

9L19

9L57

9L10

PST

1602LIVOCKPS

1274MACKAY

9L08 9L43

Ruth Lake Area

1655DAWES240


THU, NOV 27 2014 15:10

Brintnell 876S

1080WESLY C4

Christina Lake Area

High Prairie Area


Peace River Area

Dover 888S

1.1263.6

9L15

9L56-1

9L56-2



9L58

9L58

1.1267.4


36.9

-42.

3

-36.

7

1605THICKWD2

29

71.8

35.9

SW

-241.2

1.1263.6

12.9

1.1269.91.

4

-15.

4

-1.4

-8.7

1260LOU CR.4

1.1257.2 1.1

259.0165.

0

-47.

4

-160

.1

138N BARRH4

31.8

204MCMILLA4

-46.8

51.3

47.0-62.9

22.6

-22.

6

-7.4

8.8

0.0

-0.0

-0.0

1.026.0

19226WABASCA9

0.0

1.025.7

18226WABASCA8

1.136.4

SW

85.7

10605THICKWD4

Page A- 11

SW

65.6

-47.

9

-28.

0-2

9.4

19.5

-16.

2

1.1264.9

31.7

-31.

744

.3 1.1263.6

1.1263.7

-124

.0

SW

-0.0

-44.

2

1.1259.954

.7

666DOVER

1.1266.4

16.4

-30.

011

.8

3.4

9.6

-3.4

-21.

8

1.1266.4 -5

.1

9.9

5.0

1.1266.4

9.9

5.0

79.0

13.2

-78.

7

765STONE_01

1.1263.3-8

1.4

-44.

1

81.4

41.5

1288LIVOCK01

1228MITS E.4

-34.

7

1800ER_01

-5.1

-9.9

44.2

-9.4

-5.0

9.5

3.3

-10.2 9.6

-9.9

18.2

75.3

-42.

5

-74.

2

-19.

8

-54.

4

-27.6

-12.9

-27.

6

-12.

8

16.2

1.0142.3

20.6

75.6H

175.7

-18.11.1270.1

-165

.3

-65.

3

74.0

1.0142.4

-83.9

1.1264.3

1.1267.5

1.1264.1

1280BRINT02

1.0142.8

1669AMRBUS01

1.1263.8

18288LIVOCK03

1008SALE01

1626AMRBUS04

1670BWC01

-16.

4

1200RUTH LK4

DoverArea

1006GERMAIN1

-46.

7

9L409L913

9L30

9L07

9L07

9L68

Livock 939S

9L89

SVC

9L019L95

9L82

9L28

9L19

9L57

9L10

PST

1602LIVOCKPS

1274MACKAY

9L08 9L43

Ruth Lake Area

1655DAWES240


THU, NOV 27 2014 15:10

Brintnell 876S

1080WESLY C4

Christina Lake Area

High Prairie Area


Peace River Area

Dover 888S

1.1262.8

9L15

9L56-1

9L56-2



9L58

9L58

1.1267.3


34.0

-41.

8

-33.

9

1605THICKWD2

29

71.8

35.9

SW

-241.2

1.1263.6

12.3

1.1269.84.

1

-16.

0

-4.1

-8.1

1260LOU CR.4

1.1257.2 1.1

258.1

-172

.8

175.

9

-54.

7

138N BARRH4

41.3

204MCMILLA4

-48.0

50.8

48.3-62.4

22.6

-22.

6

-7.4

8.8

0.0

-0.0

-0.0

1.025.9

19226WABASCA9

0.0

1.025.8

18226WABASCA8

1.136.4

SW

85.7

10605THICKWD4

Page A- 12

ATCO Electric

B-1

R0

ATTACHMENT B Post-Connection System Load Flow Plots

(2016 SP and 2016 WP)

ATCO Electric

B-2

R0

System Load Flow Results Load Flow Diagrams The post-connection load flow diagrams for Category A and selected Category B contingencies are provided in this section. The following table presents the list of the load flow diagrams.

Table B-1: List of post-connection load flow diagrams

Scenario Load flow diagram Page number

2016 SP

N-0, System Normal Condition B-3 N-1, Loss of 9L15 B-4 N-1, Loss of 9L10 B-5 N-1, Loss of 9L40 B-6 N-1, Loss of 9L913 B-7

2016 WP

N-0, System Normal Condition B-8 N-1, Loss of 9L15 B-9 N-1, Loss of 9L10 B-10 N-1, Loss of 9L40 B-11 N-1, Loss of 9L913 B-12

SW

50.6

-29.

8

-27.

2-5

7.1

48.0

-14.

8

1.1267.9

68.5

-68.

228

.2 1.1266.5

1.1267.0

-125

.7

SW

31.0

-28.

2

1.1261.611

7.1

666DOVER

1.1268.8

10.6

-22.

23.

5

6.1

-0.7

-6.1

-11.

7

1.1268.8 -4

.2

8.3

4.1

1.1268.8

8.3

4.1

72.3

-4.9

-72.

1

765STONE_01

1.1267.1-6

8.6

-36.

7

68.6

33.9

1288LIVOCK01

1228MITS E.4

-17.

8

1800ER_01

-4.2

-8.3

28.2

-6.0

-3.1

6.0

1.3

-6.1 5.5

-8.3

11.4

-1.1

-33.

6

1.1

-37.

3

-115

.6

-17.4

-6.8

-17.

4

-6.8

14.8

1.0142.8

38.2

49.4R

148.0

-11.41.1272.3

-139

.4

-50.

2

106.

1

1.0142.8

-115.3

1.1267.3

1.1269.3

1.1267.8

1280BRINT02

1.0143.1

1669AMRBUS01

1.1264.0

18288LIVOCK03

1008SALE01

1626AMRBUS04

1670BWC01

-10.

6

1200RUTH LK4

DoverArea

1006GERMAIN1

-59.

1

9L409L913

9L30

9L07

9L07

9L68

Livock 939S

9L89

SVC

9L019L95

9L82

9L28

9L19

9L57

9L10

PST

1602LIVOCKPS

1274MACKAY

9L08 9L43

Ruth Lake Area

1655DAWES240

CATEGORY A, N-G-02016 SP WITH PROJECT ALTERNATIVE 1

THU, NOV 27 2014 13:57

Brintnell 876S

1080WESLY C4

Christina Lake Area

High Prairie Area


Peace River Area

Dover 888S

1.1264.8

9L15

9L56-1

9L56-2



9L58

9L58

1.1269.1


14.3

-41.

5

-14.

2

1605THICKWD2

29

45.0

22.5

SW

-121.3

1.1264.4

11.1

1.1270.718

.0

-30.

2

-17.

9

6.1

1260LOU CR.4

1.1261.2 1.1

261.5

-93.

8

94.7

-32.

1

158.

7

-38.

7

-154

.3

138N BARRH4

20.04.8

204MCMILLA4

-37.4

74.2

37.7-85.3

43.5

-43.

3

-12.

717

.7

-1.1

1.1

3.7

1.026.0

19226WABASCA9

-3.7

1.025.8

18226WABASCA8

1.136.5

SW

86.3

10605THICKWD4

Page B- 3

SW

50.7

-34.

3

-45.

7-3

8.1

29.1

-34.

0

1.1264.3

67.0

-66.

828

.0 1.1261.1

1.1266.0

-124

.9

SW

-0.0

-27.

9

1.1259.311

5.5

666DOVER

1.1266.8

10.3

-41.

523

.5

6.5

19.6

-6.4

-31.

8

1.1266.8 -4

.2

8.3

4.1

1.1266.8

8.3

4.1

72.2

-5.3

-72.

0

765STONE_01

1.1266.3-6

8.6

-36.

7

68.6

33.9

1288LIVOCK01

1228MITS E.4

-17.

2

1800ER_01

-4.2

-8.3

27.9

-6.0

-3.1

6.0

1.4

-6.1 5.5

-8.3

11.4

-114

.2

-17.4

-6.9

-17.

4

-6.9

34.0

1.0140.9

19.2

54.2R

148.0

-11.41.1271.6

-139

.4

-50.

3

98.4

1.0140.9

-107.7

1.1263.0

1.1268.5

1.1267.0

1280BRINT02

1.0141.2

1669AMRBUS01

1.1263.5

18288LIVOCK03

1008SALE01

1626AMRBUS04

1670BWC01

-10.

2

1200RUTH LK4

DoverArea

1006GERMAIN1

-40.

2

9L409L913

9L30

9L07

9L07

9L68

Livock 939S

9L89

SVC

9L019L95

9L82

9L28

9L19

9L57

9L10

PST

1602LIVOCKPS

1274MACKAY

9L08 9L43

Ruth Lake Area

1655DAWES240

CATEGORY B, LOSS OF 9L152016 SP WITH PROJECT ALTERNATIVE 1

THU, NOV 27 2014 13:57

Brintnell 876S

1080WESLY C4

Christina Lake Area

High Prairie Area


Peace River Area

Dover 888S

1.1260.2

9L15

9L56-1

9L56-2



9L58

9L58

1.1268.3


14.2

-43.

1

-14.

1

1605THICKWD2

29

45.0

22.5

SW

-121.3

1.1264.4

12.9

1.1270.218

.1

-29.

0

-18.

0

5.0

1260LOU CR.4

1.1260.4 1.1

260.7

-91.

9

92.7

-22.

0

157.

5

-32.

9

-153

.3

138N BARRH4

14.3

-5.3

204MCMILLA4

-37.4

68.6

37.7-79.8

43.5

-43.

3

-12.

717

.7

-1.1

1.1

3.7

1.026.1

19226WABASCA9

-3.7

1.025.9

18226WABASCA8

1.136.5

SW

86.3

10605THICKWD4

Page B- 4

SW

57.7

-28.

1

-38.

529

.00.

0

1.1269.5

48.9

-48.

8

1.1263.0

1.1266.1

-126

.1

SW

30.7

1.1260.497

.0

666DOVER

1.1269.6

-17.

6

-7.1

-11.

7

34.3

-15.

7

-34.

3

3.5

1.1269.6 -4

.2

8.3

4.1

1.1269.6

8.3

4.1

70.9

-4.5

-70.

7

765STONE_01

1.1267.4-6

8.6

-36.

7

68.6

33.9

1288LIVOCK01

1228MITS E.4

-18.

3

1800ER_01

-4.2

-8.3

-0.0

-6.0

-3.1

6.0

1.3

-6.1 5.4

-8.3

11.4

-9.9

-24.

0

9.9

-45.

5

-96.

1

-17.4

-6.8

-17.

4

-6.8

1.0143.7

19.5

47.5R

148.0

-11.41.1272.3

-139

.4

-57.

2

110.

9

1.0143.7

-119.8

1.1269.5

1.1269.7

1.1268.1

1280BRINT02

1.0144.0

1669AMRBUS01

1.1264.2

18288LIVOCK03

1008SALE01

1626AMRBUS04

1670BWC01

17.6

1200RUTH LK4

DoverArea

1006GERMAIN1

-42.

7

9L409L913

9L30

9L07

9L07

9L68

Livock 939S

9L89

SVC

9L019L95

9L82

9L28

9L19

9L57

9L10

PST

1602LIVOCKPS

1274MACKAY

9L08 9L43

Ruth Lake Area

1655DAWES240


THU, NOV 27 2014 13:57

Brintnell 876S

1080WESLY C4

Christina Lake Area

High Prairie Area


Peace River Area

Dover 888S

1.1261.9

9L15

9L56-1

9L56-2



9L58

9L58

1.1269.5


2.6

-37.

5

-2.6

1605THICKWD2

29

45.0

22.5

SW

-121.3

1.1264.4

6.9

1.1270.629

.1

-33.

8

-29.

0

10.0

1260LOU CR.4

1.1261.0 1.1

261.3

-83.

1

83.8

-24.

6

148.

5

-34.

6

-144

.7

138N BARRH4

13.2

-3.7

204MCMILLA4

-42.5

77.6

42.9-88.5

43.5

-43.

3

-12.

717

.7

-1.1

1.1

3.7

1.026.0

19226WABASCA9

-3.7

1.025.8

18226WABASCA8

1.136.5

SW

86.3

10605THICKWD4

Page B- 5

SW

54.8

-31.

7

-31.

3-6

0.0

50.5

-19.

0

1.1266.5

30.7

-30.

611

.9 1.1264.6

1.1265.9

-125

.4

SW

30.7

-11.

9

1.1257.678

.8

666DOVER

1.1268.0

-5.7

-26.

37.

8

22.4 3.8

-22.

4

-16.

0

1.1268.0 -4

.2

8.3

4.1

1.1268.0

8.3

4.1

71.5

-4.9

-71.

3

765STONE_01

1.1266.8-6

8.6

-36.

7

68.6

33.9

1288LIVOCK01

1228MITS E.4

-17.

7

1800ER_01

-4.2

-8.3

11.9

-6.0

-3.1

6.0

1.4

-6.1 5.5

-8.3

11.4

20.2

-33.

9

-20.

2

-35.

7

-77.

9

-17.4

-6.8

-17.

4

-6.8

19.0

1.0142.1

41.1

51.4R

148.0

-11.41.1271.9

-139

.4

-54.

3

103.

9

1.0142.1

-113.0

1.1265.8

1.1269.0

1.1267.4

1280BRINT02

1.0142.4

1669AMRBUS01

1.1263.8

18288LIVOCK03

1008SALE01

1626AMRBUS04

1670BWC01

5.7

1200RUTH LK4

DoverArea

1006GERMAIN1

-64.

6

9L409L913

9L30

9L07

9L07

9L68

Livock 939S

9L89

SVC

9L019L95

9L82

9L28

9L19

9L57

9L10

PST

1602LIVOCKPS

1274MACKAY

9L08 9L43

Ruth Lake Area

1655DAWES240


THU, NOV 27 2014 13:58

Brintnell 876S

1080WESLY C4

Christina Lake Area

High Prairie Area


Peace River Area

Dover 888S

1.1262.4

9L15

9L56-1

9L56-2



9L58

9L58

1.1268.8


7.6

-40.

2

-7.5

1605THICKWD2

29

45.0

22.5

SW

-121.3

1.1264.4

9.8

1.1270.324

.4

-31.

5

-24.

3

7.6

1260LOU CR.4

1.1260.4 1.1

259.2202.

7

-32.

3

-195

.6

138N BARRH4

29.6

204MCMILLA4

-40.3

72.5

40.6-83.6

43.5

-43.

3

-12.

717

.7

-1.1

1.1

3.7

1.026.0

19226WABASCA9

-3.7

1.025.8

18226WABASCA8

1.136.5

SW

86.3

10605THICKWD4

Page B- 6

SW

59.0

-31.

8

-27.

2-5

7.0

47.3

-14.

8

1.1266.6

24.9

-24.

7-4

.8 1.1264.9

1.1265.9

-125

.4

SW

30.7

4.8

1.1258.272

.8

666DOVER

1.1268.0

-22.

4

-22.

03.

6

39.1

-0.2

-39.

1

-11.

9

1.1268.0 -4

.2

8.3

4.1

1.1268.0

8.3

4.1

70.7

-4.8

-70.

5

765STONE_01

1.1266.8-6

8.6

-36.

7

68.6

33.9

1288LIVOCK01

1228MITS E.4

-17.

9

1800ER_01

-4.2

-8.3

-4.8

-6.0

-3.1

6.0

1.4

-6.1 5.5

-8.3

11.4

9.4

-33.

4

-9.3

-36.

7

-72.

0

-17.4

-6.8

-17.

4

-6.8

14.8

1.0142.1

38.1

51.5R

148.0

-11.41.1271.7

-139

.4

-58.

5

104.

8

1.0142.2

-113.8

1.1266.1

1.1269.0

1.1267.4

1280BRINT02

1.0142.5

1669AMRBUS01

1.1263.7

18288LIVOCK03

1008SALE01

1626AMRBUS04

1670BWC01

22.4

1200RUTH LK4

DoverArea

1006GERMAIN1

-62.

3

9L409L913

9L30

9L07

9L07

9L68

Livock 939S

9L89

SVC

9L019L95

9L82

9L28

9L19

9L57

9L10

PST

1602LIVOCKPS

1274MACKAY

9L08 9L43

Ruth Lake Area

1655DAWES240


THU, NOV 27 2014 13:58

Brintnell 876S

1080WESLY C4

Christina Lake Area

High Prairie Area


Peace River Area

Dover 888S

1.1262.8

9L15

9L56-1

9L56-2



9L58

9L58

1.1268.7


0.7

-38.

2

-0.7

1605THICKWD2

29

45.0

22.5

SW

-121.3

1.1264.4

7.7

1.1270.030

.9

-33.

4

-30.

8

9.7

1260LOU CR.4

1.1258.4 1.1

260.4

-192

.3

196.

0

-36.

9

138N BARRH4

26.9

204MCMILLA4

-43.4

73.2

43.7-84.2

43.5

-43.

3

-12.

717

.7

-1.1

1.1

3.7

1.026.1

19226WABASCA9

-3.7

1.025.6

18226WABASCA8

1.136.5

SW

86.3

10605THICKWD4

Page B- 7

SW

58.4

-36.

8

-31.

1-3

6.9

27.3

-19.

5

1.1265.1

44.6

-44.

553

.8 1.1263.6

1.1264.0

-124

.2

SW

-0.0

-53.

7

1.1261.392

.6

666DOVER

1.1266.6

27.7

-32.

314

.3

-9.0

11.4

9.0

-23.

6

1.1266.6 -4

.8

9.3

4.7

1.1266.6

9.3

4.7

75.2

10.3

-75.

0

765STONE_01

1.1263.9-7

6.2

-41.

1

76.3

38.4

1288LIVOCK01

1228MITS E.4

-32.

1

1800ER_01

-4.8

-9.3

53.7

-8.8

-4.7

8.9

2.9

-9.5 8.9

-9.3

17.0

67.9

-41.

3

-67.

0

-22.

4

-91.

7

-25.9

-11.8

-25.

9

-11.

8

19.5

1.0142.5

16.3

63.0R

175.7

-17.01.1270.3

-166

.0

-58.

1

72.3

1.0142.6

-82.4

1.1264.4

1.1267.7

1.1264.6

1280BRINT02

1.0143.0

1669AMRBUS01

1.1264.0

18288LIVOCK03

1008SALE01

1626AMRBUS04

1670BWC01

-27.

6

1200RUTH LK4

DoverArea

1006GERMAIN1

-40.

1

9L409L913

9L30

9L07

9L07

9L68

Livock 939S

9L89

SVC

9L019L95

9L82

9L28

9L19

9L57

9L10

PST

1602LIVOCKPS

1274MACKAY

9L08 9L43

Ruth Lake Area

1655DAWES240

CATEGORY A, N-G-02016 WP WITH PROJECT ALTERNATIVE 1

THU, NOV 27 2014 15:11

Brintnell 876S

1080WESLY C4

Christina Lake Area

High Prairie Area


Peace River Area

Dover 888S

1.1262.5

9L15

9L56-1

9L56-2



9L58

9L58

1.1267.4


45.7

-43.

7

-45.

5

1605THICKWD2

29

67.3

33.6

SW

-242.0

1.1264.0

14.7

1.1270.2-7

.1

-12.

5

7.1

-11.

6

1260LOU CR.4

1.1258.5 1.1

260.1

-102

.6

103.

7

-49.

3

118.

4

-41.

0

-115

.9

138N BARRH4

12.6

23.9

204MCMILLA4

-42.8

49.6

43.0-61.3

43.4

-43.

3

-14.

119

.2

-1.2

1.2

3.7

1.025.9

19226WABASCA9

-3.7

1.025.8

18226WABASCA8

1.136.4

SW

86.0

10605THICKWD4

Page B- 8

SW

63.4

-42.

1

-49.

6-3

1.3

23.2

-38.

5

1.1260.8

92.3

-91.

934

.2 1.1257.3

1.1261.9

-123

.2

SW

-0.0

-34.

1

1.1258.014

1.4

666DOVER

1.1264.3

8.1

-51.

233

.9

10.6

31.4

-10.

5

-43.

2

1.1264.3 -4

.8

9.3

4.7

1.1264.3

9.3

4.7

74.3

9.8

-74.

1

765STONE_01

1.1262.9-7

6.2

-41.

1

76.3

38.5

1288LIVOCK01

1228MITS E.4

-31.

5

1800ER_01

-4.8

-9.3

34.1

-8.8

-4.7

8.9

2.9

-9.5 8.9

-9.3

17.0

-139

.4

-25.9

-11.8

-25.

9

-11.

8

38.5

1.0141.9

10.7

68.8R

175.7

-17.01.1269.5

-165

.9

-63.

1

64.5

1.0141.9

-74.6

1.1259.3

1.1266.7

1.1263.6

1280BRINT02

1.0142.4

1669AMRBUS01

1.1263.4

18288LIVOCK03

1008SALE01

1626AMRBUS04

1670BWC01

-8.0

1200RUTH LK4

DoverArea

1006GERMAIN1

-28.

1

9L409L913

9L30

9L07

9L07

9L68

Livock 939S

9L89

SVC

9L019L95

9L82

9L28

9L19

9L57

9L10

PST

1602LIVOCKPS

1274MACKAY

9L08 9L43

Ruth Lake Area

1655DAWES240

CATEGORY B, LOSS OF 9L152016 WP WITH PROJECT ALTERNATIVE 1

THU, NOV 27 2014 15:11

Brintnell 876S

1080WESLY C4

Christina Lake Area

High Prairie Area


Peace River Area

Dover 888S

1.1256.9

9L15

9L56-1

9L56-2



9L58

9L58

1.1266.4


37.6

-44.

1

-37.

4

1605THICKWD2

29

67.3

33.6

SW

-242.0

1.1264.0

15.0

1.1269.40.

6

-13.

0

-0.6

-11.

0

1260LOU CR.4

1.1257.4 1.1

258.7

-131

.3

133.

0

-37.

4

124.

8

-33.

4

-122

.0

138N BARRH4

7.1

16.1

204MCMILLA4

-46.4

44.0

46.5-55.7

43.4

-43.

3

-14.

119

.2

-1.2

1.2

3.7

1.025.9

19226WABASCA9

-3.7

1.025.8

18226WABASCA8

1.136.4

SW

86.0

10605THICKWD4

Page B- 9

SW

71.9

-34.

7

-16.

56.

60.

0

1.1266.9

7.7

-7.7

1.1260.9

1.1263.6

-124

.6

SW

-0.0

1.1260.655

.1

666DOVER

1.1267.6

-26.

0

-12.

3-6

.1

44.7

-8.7

-44.

6

-3.2

1.1267.6 -4

.8

9.3

4.7

1.1267.6

9.3

4.7

72.7

10.7

-72.

5

765STONE_01

1.1264.3-7

6.2

-41.

1

76.3

38.4

1288LIVOCK01

1228MITS E.4

-32.

8

1800ER_01

-4.8

-9.3

0.0

-8.8

-4.7

8.9

2.9

-9.5 8.8

-9.3

17.0

50.5

-32.

5

-50.

0

-32.

9

-54.

8

-25.9

-11.7

-25.

9

-11.

7

1.0143.5

-4.0

60.7R

175.7

-17.01.1270.4

-166

.0

-71.

6

78.8

1.0143.6

-88.4

1.1266.9

1.1268.1

1.1265.0

1280BRINT02

1.0144.0

1669AMRBUS01

1.1264.3

18288LIVOCK03

1008SALE01

1626AMRBUS04

1670BWC01

26.0

1200RUTH LK4

DoverArea

1006GERMAIN1

-22.

5

9L409L913

9L30

9L07

9L07

9L68

Livock 939S

9L89

SVC

9L019L95

9L82

9L28

9L19

9L57

9L10

PST

1602LIVOCKPS

1274MACKAY

9L08 9L43

Ruth Lake Area

1655DAWES240


THU, NOV 27 2014 15:11

Brintnell 876S

1080WESLY C4

Christina Lake Area

High Prairie Area


Peace River Area

Dover 888S

1.1260.4

9L15

9L56-1

9L56-2



9L58

9L58

1.1267.9


23.4

-38.

0

-23.

3

1605THICKWD2

29

67.3

33.6

SW

-242.0

1.1264.0

8.1

1.1270.014

.1

-18.

6

-14.

1

-5.4

1260LOU CR.4

1.1258.5 1.1

260.0

-82.

7

83.4

-42.

6

99.7

-37.

0

-98.

0

138N BARRH4

4.8

15.0

204MCMILLA4

-52.6

54.2

52.9-65.6

43.4

-43.

2

-14.

119

.1

-1.2

1.2

3.7

1.026.0

19226WABASCA9

-3.7

1.025.6

18226WABASCA8

1.136.4

SW

86.0

10605THICKWD4

Page B- 10

SW

62.8

-37.

5

-31.

3-3

1.8

21.9

-19.

4

1.1264.5

4.4

-4.4

36.2 1.1

262.8

1.1263.4

-124

.1

SW

-0.0

-36.

1

1.1259.951

.9

666DOVER

1.1266.3

10.1

-32.

013

.9

8.5

11.0

-8.5

-23.

2

1.1266.3 -4

.8

9.3

4.7

1.1266.3

9.3

4.7

74.4

10.3

-74.

2

765STONE_01

1.1263.8-7

6.2

-41.

1

76.3

38.5

1288LIVOCK01

1228MITS E.4

-32.

2

1800ER_01

-4.8

-9.3

36.1

-8.8

-4.7

8.9

2.9

-9.5 8.9

-9.3

17.0

91.1

-42.

0

-89.

5

-16.

8

-51.

6

-25.9

-11.8

-25.

9

-11.

8

19.4

1.0142.2

11.3

63.7R

175.7

-17.01.1270.2

-165

.9

-62.

5

72.1

1.0142.3

-82.1

1.1263.8

1.1267.6

1.1264.5

1280BRINT02

1.0142.7

1669AMRBUS01

1.1264.0

18288LIVOCK03

1008SALE01

1626AMRBUS04

1670BWC01

-10.

1

1200RUTH LK4

DoverArea

1006GERMAIN1

-37.

7

9L409L913

9L30

9L07

9L07

9L68

Livock 939S

9L89

SVC

9L019L95

9L82

9L28

9L19

9L57

9L10

PST

1602LIVOCKPS

1274MACKAY

9L08 9L43

Ruth Lake Area

1655DAWES240


THU, NOV 27 2014 15:11

Brintnell 876S

1080WESLY C4

Christina Lake Area

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Page B- 11

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THU, NOV 27 2014 15:11

Brintnell 876S

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Page B- 12

APPENDIX B TFO CAPITAL COST ESTIMATES

Estimate Summary

Proposal to Provide Services (PPS) - Estimate SummaryProject:TFO:Prepared by:Date:Accuracy:

System Portion Customer Portion TOTAL Capital Maintenance

Material -$ -$ -$ -$ Labour -$ -$ -$ -$

Total-Transmission line -$ -$ -$ -$

Material -$ 145,992$ 145,992$ -$ Labour -$ 867,055$ 867,055$ -$

Total-Substations -$ 1,013,047$ 1,013,047$ -$

Material -$ -$ -$ -$ Labour -$ -$ -$ -$

Total-Telecommunication -$ -$ -$ -$

Proposal to Provide Service -$ 108,000$ 108,000$ -$ Facility Applications -$ 92,210$ 92,210$ -$ Land Rights - Easements -$ -$ -$ -$ Land - Damage Claims -$ -$ -$ -$ Land - Acquisitions -$ -$ -$ -$ Owners Costs -$ 200,210$ 200,210$ -$

Procurement -$ 52,450$ 52,450$ -$ Project Management -$ 256,960$ 256,960$ -$ Construction Management -$ 144,300$ 144,300$ -$ Contingency -$ 198,000$ 198,000$ -$ Distributed Costs -$ 651,710$ 651,710$ -$

Total Owners and Dist. Costs -$ 851,920$ 851,920$ -$

Total Direct Costs -$ 1,864,967$ 1,864,967$ -$

Salvage - Transmission Line Labour -$ -$ -$ -$ Salvage - Substation Labour -$ 42,900$ 42,900$ -$ Land Remediation and Reclamation -$ -$ -$ -$ Salvage Costs -$ 42,900$ 42,900$ -$ Other Costs

Inflation -$ 45,824$ 45,824$ -$ E&S -$ 193,333$ 193,333$ -$

AFUDC -$ -$ -$ -$

Total Indirect Costs -$ 282,057$ 282,057$ -$

TOTAL PROJECT COSTS -$ 2,147,024$ 2,147,024$ -$

Wabasca 720S Substation 25 kV Feeder Breaker AddATCO ElectricMoataz Nassar2015-01-30

Transmission Line Costs

Owner Costs

Distributed Costs

Substation Facilities Cost

Telecommunications Cost

+20 / -10%

PPS mapping ‐ 51745 Wabasca revised 150202.xlsx

APPENDIX C PARTICIPANT INVOLVEMENT PROGRAM (PIP)

Alberta Electric System Operator Project 1491 April 2015


1.0 Participant Involvement Program (PIP) From September 2014 to May 2015, the AESO conducted a Participant Involvement Program (PIP) to assist in preparing its Wabasca 720S Substation Modification Needs Identification Document (NID). The AESO directed transmission facility owner (TFO), ATCO Electric Ltd. (ATCO), to assist the AESO in providing notification in accordance with NID14 and Appendix A2 of Alberta Utilities Commission Rule 007. 1.1 Stakeholder Notification The AESO’s PIP was designed to notify and provide information to all occupants, residents and landowners within the notification area of the proposed development, as well as to other interested parties, including the following government bodies, agencies and other stakeholder groups (Stakeholders):

• Alberta Culture (formerly Alberta Culture and Community Spirit) • Alberta Environment and Sustainable Resource Development • Alberta Transportation • Alberta Government Services • Municipal District of Opportunity No. 17 • Industry Canada • NAV Canada • Transport Canada • Telus Communications Inc. • Northland School Division No. 61 • Big Stone Cree Nation

The AESO used a variety of methods to notify stakeholders on the need for the Wabasca Substation Modification. The AESO developed a one-page need overview document that described the need for the proposed transmission development. A copy of this document was posted to the AESO website at http://www.aeso.ca/transmission/31687.html on February 5, 2015. A copy of the need overview is included as Attachment 1. The need overview was also included with ATCO’s project-specific information package mailed on September 26, 2014 to the Stakeholders noted above. Attachment 2 includes a copy of ATCO’s brochure.

http://www.aeso.ca/transmission/31687.html


To ensure that Stakeholders had the opportunity to provide feedback, the AESO also provided stakeholders with a dedicated, toll-free telephone line (1-888-866-2959) and a dedicated email address ([email protected]). AESO contact information, along with the AESO’s mailing address (2500, 330 5th Ave, SW, Calgary) and website address (www.aeso.ca), and a privacy statement that described how the AESO honours Alberta’s Personal Information Protection Act, were included on the need overview related to this application. As directed by the AESO, the TFO was prepared to direct any inquiries or concerns about the project need to the AESO. The TFO has indicated that Stakeholders have not identified any concerns or objections with the need for the proposed transmission development. 1.2 Public Notification Most recently, the AESO published a Public Notification of NID Filing to the AESO website at http://www.aeso.ca/transmission/31687.html on April 13, 2015 and in the Stakeholder Newsletter on April 14, 2015. Copies of the Public Notification of NID Filing and the Stakeholder Newsletter posting have been included as Attachment 3 and 4, respectively. 1.3 Concerns and Objections Raised

The AESO has received no indication of concern or objections from any party about the need for the proposed transmission development. 1.4 List of Attachments

• Attachment 1 – AESO Need Overview • Attachment 2 – ATCO’s Information Brochure – Wabasca Substation

Alterations (September 2014) • Attachment 3 – AESO Public Notification of NID Filing (AESO Website

Posting) • Attachment 4 – AESO Stakeholder Newsletter Posting

http://www.aeso.ca/transmission/31687.html


Attachment 1 – AESO Need Overview


Attachment 2 – ATCO’s Information Brochure – Wabasca Substation Alterations (September 2014)


Attachment 3 – AESO Public Notification of NID Filing (AESO Website Posting)


Attachment 4 – AESO Stakeholder Newsletter Posting

APPENDIX D INFORMATION REGARDING RULE 007, SECTION 6.1 - NID13

10035 - 105 Street, Edmonton, AB, Canada T5J 2V6 Tel: 1-866-600-0022 Fax: 780-420-5030 www.atcoelectric.com

December 9, 2014 Jeremy Cahill Alberta Electric System Operator 2500, 330 – 5th Avenue SW Calgary, AB T2P 0L4 Dear Mr. Cahill: RE: Confirmation of AUC Rule 007, NID 13 Content in Facility Application

Wabasca 720S Breaker Addition AESO Project File No. 1491 ATCO Electric Ltd. will address seven aspects of AUC Rule 007, NID 13 in the Facility Application for the above-referenced project, where applicable:

1. Agricultural Impact 2. Residential Impact 3. Environmental Impact 4. Cost 5. Electrical Considerations 6. Visual Impacts 7. Special Constraints

Please contact the undersigned if you require further information. Sincerely, ATCO Electric Ltd. <Original Signed By> Wesley Caldwell Right-of-Way Planner Tel: 780-733-2700 Email: [email protected]

APPENDIX E DFO NEED FOR DEVELOPMENT REPORT

Project 51745 –Wabasca 720S Substation Distribution Deficiency Report

Page 1 of 15

1. Summary

ATCO Electric Distribution Division (AE DFO) has received a request from a customer

to serve loads for a new in situ oil sands plant in the Wabasca area. The customer has

requested service in two phases. This report covers phase one.

Three alternatives were considered:

1. Use existing transmission infrastructure (Distribution Only),

2. Install a 25 kV breaker at Wabasca 720S and build a new 25 kV line, and

3. Build a new POD and 25 kV line.

Violation of feeder loading criteria in AE DFO’s “Guideline for Adding 25 kV Breakers”

occurs with the distribution only alternative and the new POD alternative requires the

most transmission system development by a significant margin. Therefore Alternatives 1

and 3 were rejected and AE DFO’s preferred solution to serve the proposed load is

Alternative 2, install a 25 kV breaker at Wabasca 720S and build a new 25 kV line.

2. Background

Wabasca 720S is located at LSD NW 23-80-25-W4M about 1 km north of South

Wabasca Lake. Over 70% of the load demands on this POD come from oilfield and

industrial customers.

Wabasca 720S is operated as a T-tap connected to 240 kV transmission line 9L56. This

POD has two 240 – 25 kV transformers, 901T and 902T rated at 20/26.6/33.3 MVA and

30/40/50 MVA respectively. There are four existing feeders from this POD; 5L537,

5L295, 5L712 and 5L114 (see Figure 1).


Page 2 of 15

Figure 1 – Simplified SLD of Existing Wabasca 720S Substation

720S Wabasca

Substation240 kV

9L56

BRINTNELL

240 kV

9L56

MITSUE

EAST

901

901T

20/26.6/33.3 MVA

505505B 505A

504504B 504A

500D4

501501A501B

25kV

5L537

500D1

N.O.

503503A503B

25kV

5L295

500D2

N.O.

502502A502B

25kV

5L712

500D3

N.O.902T

30/40/50 MVA25kV

5L114

506

9L56D3

9L56D2

901B901A

902B902A

900D1

902

901TD1

902TD1506B

N.O

N.O

Transformer 901T is limited to maximum loading of 22 MVA due to voltage regulation

problems caused by high impedance. Currently all POD load is served through 902T with

901T serving as a backup for contingencies.

For Phase 1 of the project, the customer plans to have three phase service for the loads

shown in Table 1.

NOTE: Phase 2 is anticipated for fourth quarter 2018 with an estimated additional

operating load of 20 MW. A separate System Access Service Request (SASR)

will be submitted for this when the customer applies for service.


Page 3 of 15

Location Operating

Load (kW)

Secondary

Voltage (V)

Largest

Motor (HP) Description

LSD NW-12-81-24-W4M 9151 2400/4160 6600

Central

Processing

Facility

LSD NW-12-81-24-W4M 2343 347/600 250

Central

Processing

Facility

LSD SE-13-81-24-W4M 909 347/600 75 Well Pad

102

LSD SW-18-81-23-W4M 909 347/600 75 Well Pad

103

LSD 4-6-81-23-W4M 40 347/600 25 Source Well

201

LSD 15-12-81-24-W4M 40 347/600 25 Source Well

202

LSD 4-13-81-24-W4M 51 347/600 1.5 Disposal

Well 302

LSD 5-12-81-24-W4M 200 120/208 - Permanent

Camp

Table 1: Customer requested Loads for Phase 1 Development

3. Alternatives considered

Alternative 1: Use Existing Transmission Infrastructure (Distribution Only)

There is no existing distribution infrastructure in place to connect this load request.

Alternative 1 involves building approximately 16 km of new 25 kV mainline from a tap

point on existing distribution line 5L712 outside of Wabasca 720S to the customer’s CPF

site.

Transmission System Development:

None


Page 4 of 15

Distribution System Development:

Mainline (5L712)

Build approximately 16 km of 3x477 MCM paralleling 5L295 and 5L537 from

Wabasca 720S to LSD 6-12-81-24-W4M and tap onto 5L712 just outside the

substation.

Install an OVR at the tap point.

Install a 3x400A voltage regulator bank at SW 3-81-24-W4M.


CPF

Install a 25 kV gang switch.

Install VFI and primary metering.

Install a three phase 13 MVA, 25 – 4.16 kV MVA transformer.

Install a three phase 3 MVA, 25 kV – 600 V transformer.

Permanent Camp

Install a three phase 300 kVA, 25 kV – 208/120 V transformer at LSD 5-12-81-24-

W4M.

Pads 102 and 103, Source Well 202 and Disposal Well 302

Build approximately 4 km of 3x266 MCM from LSD 6-12-81-24-W4M to pads 102

and 103; source well 202 and disposal well 302.

Install a three phase 1.5 MVA, 25 kV – 600 V transformer at Pad 102.


Install a three phase 300 kVA, 25 kV – 600 V transformer at source well 202.

Install a three phase 300 kVA, 25 kV – 600 V transformer at disposal well 302.

Source Well 201

Build approximately 2.2 km of 3x266 MCM to source well 201.


Figure 2 below shows the distribution system development required for Alternative 1.


Page 5 of 15

Figure 2 –Wabasca 720S Distribution System Development for Alternative 1

The estimated capital cost for the distribution system development for Alternative 1 is

$4.7M ($2013, +/- 50%).

The load forecast for Alternative 1 is shown in Table 2 below.

Notes:

Because this alternative involves no transmission system development, this is also

the load forecast for the existing system.

The load on 5L537 was forecast to increase to 12.37 MW during 2013. This is not

related to the customer request initiating this DDR.

A coincidence factor of 0.896 has been applied to all new loads.

Power factors for all existing feeders were calculated based on the last recorded

peak loads and applied to existing loads going forward.

Power factor for all new loads is assumed to be 0.9.

After new load is applied, revised power factors for the POD and affected feeders

are calculated.

In 2015 2.2 MW of new load not related to this DDR will be added to 5L537,

while 3.1 MW of existing 5L537 load will be transferred permanently to 5L295.


Page 6 of 15

Peak Peak Peak Peak Peak Peak Peak Peak Peak Peak Peak Peak Peak Peak Peak Peak

PF PF MW MW MW MW MW MW MW MW MW MW MW MW MW MW MW MW

Sub No. Feeder Capacity Historical After 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

720S Wabasca 902T 98% 96% 16.51 20.05 23.66 22.75 21.58 30.84 31.05 44.77 45.51 45.51 45.51 45.63 46.57 46.57 46.57 46.57

5L537 30/40/50 MVA 99% 99% 8.71 5.81 8.02 4.78 4.13 12.37 12.46 11.14 11.93 11.93 11.93 11.93 12.94 12.94 12.94 12.94

5L295 97% 97% 3.85 9.63 10.53 7.48 6.18 6.67 6.67 10.11 10.11 10.11 10.11 10.11 10.11 10.11 10.11 10.11

5L712 97% 97% 0.00 0.00 0.00 6.51 5.69 6.43 6.55 6.55 6.55 6.55 6.55 6.68 6.68 6.68 6.68 6.68

5L712 97% 90% 0.00 0.00 0.00 0.00 0.00 0.00 0.00 11.90 11.90 11.90 11.90 11.90 11.90 11.90 11.90 11.90

5L114 98% 98% 4.80 5.45 5.49 5.89 6.19 6.35 6.36 6.36 6.36 6.36 6.36 6.36 6.36 6.36 6.36 6.36

720S Total Station 98% 96% 16.51 20.05 23.66 22.75 21.58 30.84 31.05 44.77 45.51 45.51 45.51 45.63 46.57 46.57 46.57 46.57

Notes:

A coincidence factor of 0.97 was applied to 720S feeders

Power factors for all existing feeders were calculated based on the last recorded peak loads and applied to existing loads going forward

Power factor for customer's new load addition is assumed to be 0.9

After customer's new load is added, revised power factor for the POD are applied from 2015 going forward

Recorded Predicted

Table 2 –Wabasca 720S Substation Load forecast for Alternative 1 and the Existing Transmission System


Page 7 of 15

Alternative 2: Install a 25 kV Breaker Addition at Wabasca 720S and Build a

New 25 kV Line

Alternative 2 involves installing a new 25 kV feeder breaker at 720S Wabasca substation

and building approximately 16 km of new 25 kV mainline from Wabasca 720S to the

customer’s CPF site. The distribution system development for Alternative 2 is essentially

the same as for Alternative 1, with the exception of the permanent OVR at the 5L712 tap

point.

The following transmission and distribution system development is required to serve the

requested load.


Install a new 25 kV breaker at Wabasca 720S Substation.

Install associated protection, control and metering.

The transmission system development assumed for Alternative 2 is shown in Figure 3

below.

Figure 3 – Simplified SLD of Addition at Wabasca 720S Substation for Alternative 2

720S Wabasca

Substation

902T

30/40/50 MVA

505505B 505A

506

240 kV

9L56

BRINTNELL

240 kV

9L56

MITSUE

EAST

901

9L56D3

9L56D2

901B901A

902B902A

900D1

902

902TD1

N.O

25kV

5LNEW


Mainline (5LNEW)

Build approximately 16 km of 3x477 MCM paralleling 5L295 and 5L537 from

Wabasca 720S to LSD 6-12-81-24-W4M.

Temporarily install an OVR to connect 5LNEW to 5L712 until the 25 kV breaker is in

service.




Page 8 of 15

CPF

Install a 25 kV gang switch.

Install VFI and primary metering.

Install a three 13 MVA, phase 25 – 4.16 kV transformer.

Install a three phase 3 MVA, 25 kV – 600 V transformer.

Permanent Camp

Install a three phase 300 kVA, 25 kV – 208/120 V transformer at LSD 5-12-81-24-

W4M.

Pads 102 and 103, Source Well 202 and Disposal Well 302

Build approximately 4 km of 3x266 MCM from LSD 6-12-81-24-W4M to pads 102

and 103; source well 202 and disposal well 302.




Install a three phase 300 kVA, 25 kV – 600 V transformer at disposal well 302.

Source Well 201

Build approximately 2.2 km of 3x266 MCM to source well 201.


The estimated capital cost for the distribution development for Alternative 2 is 4.7 million

dollars ($2013, +/- 50%).


Page 9 of 15

The distribution system development required for Alternative 2 is shown in Figure 4

below.

Figure 4 –Wabasca 720S Distribution System Development for Alternative 2

The load forecast for Alternative 2 is shown in Table 3 below.

Notes:



A coincidence factor of 0.896 has been applied to all new loads





are calculated.




Page 10 of 15


PF PF MW MW MW MW MW MW MW MW MW MW MW MW MW MW MW MW

Sub No. Feeder Capacity Historical After 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

720S Wabasca 902T 98% 96% 16.51 20.05 23.66 22.75 21.58 30.84 31.05 44.77 45.51 45.51 45.51 45.63 46.57 46.57 46.57 46.57

5L537 30/40/50 MVA 99% 99% 8.71 5.81 8.02 4.78 4.13 12.37 12.46 11.14 11.93 11.93 11.93 11.93 12.94 12.94 12.94 12.94

5L295 97% 97% 3.85 9.63 10.53 7.48 6.18 6.67 6.67 10.11 10.11 10.11 10.11 10.11 10.11 10.11 10.11 10.11

5L712 97% 97% 0.00 0.00 0.00 6.51 5.69 6.43 6.55 6.55 6.55 6.55 6.55 6.68 6.68 6.68 6.68 6.68

5L114 98% 98% 4.80 5.45 5.49 5.89 6.19 6.35 6.36 6.36 6.36 6.36 6.36 6.36 6.36 6.36 6.36 6.36

New Customer Feeder 90% 0.00 0.00 0.00 0.00 0.00 0.00 0.00 11.90 11.90 11.90 11.90 11.90 11.90 11.90 11.90 11.90

720S Total Station 98% 96% 16.51 20.05 23.66 22.75 21.58 30.84 31.05 44.77 45.51 45.51 45.51 45.63 46.57 46.57 46.57 46.57

Notes:


Power factors for all existing feeders were calculated based on the last recorded peak loads and applied to existing loads going forward

Power factor for customer's new load addition is assumed to be 0.9

After customer's new load is added, revised power factor for the POD is applied from 2015 going forward

Recorded Predicted

Table 3 –Wabasca 720S Substation Load Forecast For Alternative 2


Page 11 of 15

Alternative 3: Build a New POD and 25 kV Line

This alternative involves building a new 240 – 25 kV POD. For the purposes of this DDR

the new POD has been assumed to be an in/out radial bus configuration with

approximately 5 km of new double circuit 240 kV transmission line from the new POD to

existing line 9L56. (Final determination of any transmission system development is the

responsibility of the AESO and TFO.) A new 25 kV feeder is required to connect the new

POD to the customer loads.


The following transmission system development has been assumed:

Substation

Construct a new 240 – 25 kV POD at NE-11-81-24-W4M including site preparation,

bus work and control building,

Install three 240 kV breakers c/w switches, protection and control,

Install one 30/40/50 MVA, 240-25 kV LTC transformer c/w protection and control,

and

Install one 25 kV breaker c/w switches, protection and control.

Transmission Line

Construct approximately 5 km of double circuit 240 kV line from the new POD to tie

into 9L56.

The assumed transmission system development for Alternative 3 is shown in Figure 5

below.

Figure 5 – Simplified SLD of New 240-25 kV POD Substation

NEW POD

240 kV

9L56

BRINTNELL

240 kV

9L56

MITSUE

EAST

902

240-25kV

901T

30/40/50 MVA

240 kV

Disconnect

903

240 kV

Disconnect

240 kV

Breaker

240 kV

Breaker

240 kV

Breaker

901501501A501B

25kV

To

Customer

Site

25kV

Breaker

N/C

25 kV

MOD

240 kV

Disconnect

240 kV

Disconnect

240 kV

Disconnect


Page 12 of 15


Build approximately 4.5 km of 3x477 MCM from new substation to pads 102 and

103, source well 202, disposal well 302 and the CPF

Build approximately 4.9 km of 3x477 MCM from NW-12-81-24-W4M to permanent

camp and source well 201

CPF

Install a 25 kV gang switch

Install VFI and primary metering

Install a three phase13 MVA, 25 kV – 4.16 kV transformer

Install a three phase 3 MVA, 25 kV – 600V transformer

Pads 102 and 103, source Well 202 and Disposal Well 302

Install a three phase 1.5 MVA, 25 kV – 600V transformer at Pad 102

Install a three phase 1.5 MVA, 25 kV – 600V transformer at Pad 103

Install a three phase 300 kVA, 25 kV – 600V transformer at source well 202

Install a three phase 300 kVA, 25 kV – 600V transformer at disposal well 302

Permanent Camp

Install a three phase 300 kVA, 25 kV – 208Y/120V transformer

Source Well 201

Install a three phase 300 kVA, 25 kV – 600V transformer at source well 201

The estimated cost for the distribution scope of this alternative is $3.1M ($2013, +/-

50%).

The required Distribution system development for Alternative 3 is shown in Figure 6

below.


Page 13 of 15

Figure 6 - New POD Distribution System Development for Alternative 3

LOAD FORECAST for Alt 3

The load forecasts for Alternative 3 are shown in Tables 4 and 5 below.

Notes:



A coincidence factor of 0.896 has been applied to all new loads.





are calculated.




Page 14 of 15

Table 4 – New POD Load Forecast for Alternative 3


MW MW MW MW MW MW MW MW MW MW MW MW MW MW MW MW

Sub No. Feeder Capacity PF 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

720S Wabasca 902T 98% 16.51 20.05 23.66 22.75 21.58 30.84 31.05 33.15 33.91 33.91 33.91 34.03 34.99 34.99 34.99 34.99

5L537 30/40/50 MVA 99% 8.71 5.81 8.02 4.78 4.13 12.37 12.46 11.14 11.93 11.93 11.93 11.93 12.94 12.94 12.94 12.94

5L295 97% 3.85 9.63 10.53 7.48 6.18 6.67 6.67 10.11 10.11 10.11 10.11 10.11 10.11 10.11 10.11 10.11

5L712 97% 0.00 0.00 0.00 6.51 5.69 6.43 6.55 6.55 6.55 6.55 6.55 6.68 6.68 6.68 6.68 6.68

5L114 98% 4.80 5.45 5.49 5.89 6.19 6.35 6.36 6.36 6.36 6.36 6.36 6.36 6.36 6.36 6.36 6.36

720S Total Station 98% 16.51 20.05 23.66 22.75 21.58 30.84 31.05 33.15 33.91 33.91 33.91 34.03 34.99 34.99 34.99 34.99

Notes:


Recorded Predicted

Table 5 – Wabasca 720S Substation Load Forecast without Customer Load Addition


MW MW MW MW MW MW MW MW MW MW MW MW MW MW MW MW

Sub No. Feeder Capacity PF 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023

xxxS New POD 901T 90% 0.00 0.00 0.00 0.00 0.00 0.00 0.00 11.90 11.90 11.90 11.90 11.90 11.90 11.90 11.90 11.90

New Customer Feeder 30/40/50 MVA 90% 0.00 0.00 0.00 0.00 0.00 0.00 0.00 11.90 11.90 11.90 11.90 11.90 11.90 11.90 11.90 11.90

xxxS Total Station 90% 0.00 0.00 0.00 0.00 0.00 0.00 0.00 11.90 11.90 11.90 11.90 11.90 11.90 11.90 11.90 11.90

Notes:

A coincidence factor of 1.00 was applied to New POD feeders

Recorded Predicted


Page 15 of 15

4. Analysis and Recommendation

Alternative 1 results in violation of feeder loading criteria from AE DFO’s “Guideline for

Adding 25 kV Breakers”. Therefore it is rejected as an acceptable solution to serve this

load request.

Alternative 2 and 3 are both technically feasible to serve the load request. However the

assumed transmission system development to construct a new 240 kV POD far exceeds

that to add a new 25 kV breaker at Wabasca 720S. The expected incremental capital cost

for Alternative 3 versus Alternative 2 is anticipated to be far greater than the $1.6M

difference in the estimated capital costs for distribution system development.

Because Wabasca 720S has sufficient capacity to serve the requested load, the expected

higher overall costs for Alternative 3 are not justifiable. Therefore Alternative 2 is AE

DFO’s preferred alternative.

APPENDIX F AESO TRANSMISSION PLANNING CRITERIA – BASIS AND ASSUMPTIONS

Transmission Planning Criteria - Basis and Assumptions

Version 1.0

1. Introduction

This document presents the reliability standards, criteria, and assumptions to be used as the basis for planning the Alberta Transmission System. The criteria, standards and assumptions identified in this document supersede those previously established.

2. Transmission Reliability Standards and Criteria1

The AESO applies the following Alberta Reliability Standards to ensure that the transmission system is planned to meet applicable performance requirements under a defined set of system conditions and contingencies. A brief description of each of these standards is given below:

1. TPL-001-AB-0: System Performance Under Normal Conditions Category A represents a normal system condition with all elements in service (N-0). All equipment must be within its applicable rating, voltages must be within their applicable ratings and the system must be stable with no cascading outages. Under Category A, electric supply to load cannot be interrupted and generating units cannot be removed from service.

2. TPL-002-AB-0: System Performance Following Loss of a Single BES Element

Category B events result in the loss of any single element (N-1) under specified fault conditions with normal clearing. The specified elements are a generating unit, a transmission circuit, a transformer or a single pole of a direct current transmission line. The acceptable impact on the system is the same as Category A with the exception that radial customers or some local network customers, including loads or generating units, are allowed to be disconnected from the system if they are connected through the faulted element. The loss of opportunity load or opportunity interchanges is allowed. No cascading can occur.

3. TPL-003-AB-0: System Performance Following Loss of Two or More BES Elements Category C events result in the loss of two or more bulk electric system elements (sequential, N-1-1 or concurrent, N-2) under specified fault conditions and include both normal and delayed fault clearing. All of the system limits for Category A and B events apply with the exception that planned and controlled loss of firm load, firm transfers and/or generation is acceptable provided there is no cascading.

4. TPL-004-AB-0: System Performance Following Extreme BES Events Category D represents a wide variety of extreme, rare and unpredictable events, which may result in the loss of load and generation in widespread areas. The system may not be able to reach a new stable steady state, which means a blackout is a possible outcome. The AESO needs to evaluate these events, at its discretion, for risks and consequences prior to creating mitigation plans.

5. FAC-014-AB-2: Establishing and Communicating System Operating Limits The AESO is required to establish system operating limits where a contingency is not mitigated through construction of transmission facilities.

2.1 Thermal Loading Criteria

The AESO Thermal Loading Criteria require that the continuous thermal rating of any transmission element is not exceeded under normal and post-contingency operating conditions. Thermal limits are

1 A complete description of these standards are given in: AESO. Alberta Reliability Standards. Available from http://www.aeso.ca/rulesprocedures/17004.html

http://www.aeso.ca/rulesprocedures/17004.html

assumed to be 100% of the respective normal summer and winter ratings. Emergency limits are not considered in the planning evaluations.

2.2 Voltage Range and Voltage Stability Criteria

The normal minimum and maximum voltage limits as specified in the following table are used to identify Category A system voltage violations, while the extreme minimum and maximum limits are used to identify Category B and C system violations. Table 2-1 presents the acceptable steady state and contingency state voltage ranges for the AIES. Table 2-2 provides voltage stability criteria used to test the system performance.

Table 2-1: Acceptable Range of Steady State Voltage (kV)

Nominal Voltage Extreme Minimum

Normal Minimum

Normal Maximum

Extreme Maximum

500 475 500 525 550

240 216 234 252 264

260 (Northeast & Northwest)*

234 247 266 275

144 130 137 151 155

138 124 135 145 152

72 65 68.5 75.5 79

69 62 65.5 72.5 76

Table 2-2: Voltage Stability Criteria

Performance Level

Disturbance (1)(2)(3)(4) Initiated by:

Fault or No fault DC Disturbance

MW Margin (P-V method)

(5)(6)(7)

MVAr Margin (V-Q method)

(6)(7)

A

Any element such as: One Generator One Circuit One Transformer One Reactive Power Source One DC Monopole

> 5% Worst Case Scenario(8)

B

Bus Section > 5% 50% of Margin Requirement in Level A

Performance Level

Disturbance (1)(2)(3)(4) Initiated by:

Fault or No fault DC Disturbance

MW Margin (P-V method)

(5)(6)(7)

MVAr Margin (V-Q method)

(6)(7)

C

Any combination of two elements such as: A Line and a Generator A Line and a Reactive Power Source Two Generators Two Circuits Two Transformers Two Reactive Power Sources DC Bipole

> 2.5% 50% of Margin Requirement in Level A

D

Any combination of three or more elements. i.e.:

Three or More Circuits on ROW Entire Substation Entire Plant Including Switchyard

> 0 > 0

2.3 Transient Stability Analysis Assumptions

Standard fault clearing times as shown in Table 2-3 are used for the new facilities or when the actual clearing times are not available for the existing facilities. Double line-to-ground faults are applied for the Category C5 events with normal clearing times. Single line-to-ground faults are applied for Category C6 to C9 events with delayed clearing times as depicted in Table 2-4 and Table 2-5.

Table 2-3: Fault Clearing Times

Nominal Near End Far End

kV Cycles Cycles

500 4 5

240 5 6

144/138

6 8 with telecommunications

144/138

6 30 without telecommunications

Table 2-4: Stuck Breaker Clearing Times for Lines

Fault Clearing Time Fault Clearing Time Fault Clearing Time

(Cycles) (Cycles) (Cycles)

138/144 kV 240 kV 500 kV

Near End

Far End

2nd

Ckt Near End

Far End

2nd

Ckt Near End

Far End

2nd

Ckt

(for C5 and C7 Only)



15 24 24 12 6 14 9 5 11

Table 2-5: Stuck Breaker Clearing Times for Transformers

Fault Clearing Time (Cycles) Fault Clearing Time (Cycles)

240/138 kV 500/240 kV

Fault on 240 kV Side Fault on 138 kV Side Fault on 500 kV Side Fault on 240 kV Side

240 kV Side

138 kV Side

2nd

Ckt

138 kV Side

240 kV Side

2nd

Ckt 500 kV Side

240 kV Side

2nd

Ckt 240 kV Side

500 kV Side

2nd

Ckt

(for Breaker Fail)

(for Breaker Fail)

(for Breaker Fail)

(for Breaker Fail)

12 6 14 15 5 24 9 5 11 12 4 14