Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 1 of 47
TRANSMISSION GREEN ENERGY PLAN
1
2
INDEX
3
4
1.0
THE OBJECTIVES OF THE GREEN ENERGY AND GREEN ECONOMY
ACT AND HYDRO ONE’S GREEN ENERGY PLAN
7
2.0
DETERMINING NEED FOR GREEN ENERGY PROJECTS
8
3.0
TRANSMISSION PLANNING
9
4.0
MAJOR GREEN PROJECTS
10
5.0
OTHER GREEN PROJECTS
11
6.0
INFRASTRUCTURE INVESTMENT INCENTIVE APPROACH FOR
5
6
GREEN ENERGY
12
13
7.0
DEVELOPMENT WORK FOR GREEN PROJECTS
14
8.0
RECOVERY OF OM&A DEVELOPMENT COSTS
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 2 of 47
1
2
1.0
THE OBJECTIVES OF THE GREEN ENERGY AND GREEN ECONOMY
ACT AND HYDRO ONE’S GREEN ENERGY PLAN
3
4
This Green Energy Plan (the “Plan”) outlines Hydro One’s strategy to implement the
5
Government of Ontario’s policy objectives in the Green Energy and Green Economy Act,
6
2009 (“GEGEA”). All of the Green Energy Projects (“GE Projects”) discussed in this
7
Plan are included in a letter dated September 21, 2009 from the Minister of Energy and
8
Infrastructure to Hydro One. A copy of the Minister’s letter is attached in Appendix A to
9
this exhibit. The letter noted that “the Ontario Power Authority (OPA) and Hydro One
10
have worked together to identify areas in the province that would benefit from specific
11
transmission and distribution upgrades to enable renewable generation likely to be
12
forthcoming through the feed-in tariff program.” The letter went on to ask Hydro One to
13
“immediately proceed with the planning, development and implementation of
14
Transmission Projects outlined in the attached Schedule A, including seeking approvals
15
for the upgrades as soon as there is a reasonable basis to do so.”
16
17
Facilitating the Connection of Renewable Power
18
19
With respect to the connection of renewable energy generation facilities, the GE Projects
20
are required to connect new renewable generation facilities procured through the Feed-In
21
Tariff (“FIT”) program and other means. While the timing and nature of some GE
22
Projects will depend on the results of the FIT program, this Plan encompasses
23
transmission investments that will form the backbone of an electricity system re-designed
24
to integrate up to 10,000 MW and beyond of potential renewable generation.
25
26
On a long-term integrated basis, the transmission investments required to enable the
27
renewable potential in the province would significantly expand the transmission network.
28
These projects represent a major renovation of Ontario’s power system and are required
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 3 of 47
1
because:
2
•
grid and/or the Province’s load centres;
3
4
The vast majority of potential renewable generation is remote from the transmission
•
The present capability of the transmission system is inadequate for the incorporation
and transfer of the additional power;
5
6
•
New generators will require connection to the bulk system (enabler lines); and
7
•
Existing stations will require upgrades so that the necessary transformation, voltage
8
support and short-circuit capability is available to accommodate distributed
9
generation and to ensure appropriate power quality for load customers.
10
11
2.0
DETERMINING NEED FOR GREEN ENERGY PROJECTS
12
13
Hydro One continues to consult collaboratively with the Ontario Power Authority
14
(“OPA”) in defining the scope of work associated with the GE Projects. The OPA
15
performed the Transmission Availability Test (TAT) to determine which FIT applications
16
could connect using existing transmission capacity. Renewable generation that did not
17
qualify under TAT would require additional transmission facilities. In this regard the
18
OPA is developing the Economic Connection Test (ECT) analysis. The ECT will assist
19
in assessing where transmission facilities will be required to connect FIT applicants who
20
cannot connect to the existing transmission network due to lack of available capacity.
21
Hydro One’s plans for new GE projects will be based on the OPA’s identification of need
22
or direction from the government.
23
24
Hydro One’s strategy is to begin the preliminary Development Work on priority GE
25
Projects, those with the highest need as identified in consultation with the OPA and based
26
on the information presently available. Development Work involves all the work that
27
must be completed prior to construction, including: evaluating alternatives; consulting
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 4 of 47
1
with stakeholders; obtaining the necessary approvals; and identifying impacted
2
properties.
3
4
The early commencement of these priority projects is necessary to meet the in-service
5
dates for new generation. Development Work for major transmission projects can take
6
up to five or six years – significantly more than the time required to actually build the
7
new generation. This is discussed more fully in section 7.0.
8
9
When the project development work has obtained sufficient information to move forward
10
with a specific project, the formal identification of need is presented through a Section 92
11
application or a future cost of service proceeding before the Board. Hydro One will bring
12
forward Section 92 applications on the line construction projects that it is developing.
13
Some of the Schedule B projects, Enabling TS’s, SVC’s and In-Line Circuit Breakers
14
will not require Section 92 applications. Determination of need will be developed in
15
consultation with the OPA and Board approval for these projects will be sought through
16
cost of service rate applications.
17
18
3.0
TRANSMISSION PLANNING
19
20
Hydro One’s Green Energy Plan must be integrated within the context of Hydro One’s
21
overall approach to planning and managing its system. Hydro One manages its
22
transmission assets within the framework of an asset management system. This approach
23
involves systematic and coordinated activities and practices through which Hydro One
24
optimally and sustainably manages the transmission assets and asset systems, their
25
associated performance, risks and expenditures over their life cycles for the purpose of
26
achieving the corporate strategic plan. Further details about Hydro One’s Transmission
27
planning process can be found in Exhibit A, Tab 4, Schedule 1.
28
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 5 of 47
1
Hydro One primarily uses two concurrent approaches when managing its transmission
2
system and will need to broaden this approach to include the Green Energy projects:
3
1. A forward looking approach with respect to anticipated transmission system needs
4
and developments. Such outlook typically goes beyond the current business planning
5
period.
6
2. A life cycle management approach which considers and balances asset performance,
7
costs and associated risks during the asset service life in order to achieve asset
8
optimization.
9
10
1) The forward looking approach takes a longer term view for the transmission system
11
and shows that the scope and scale of anticipated needs and developments that Hydro
12
One will face are unprecedented with respect to magnitude and timeframe required for
13
implementation. There are two primary drivers for this:
14
•
Electricity System Transformation: The electricity system in Ontario is undergoing
15
major transformation as new clean energy initiatives as well as new technologies and
16
innovation are introduced. Aging generation resources must be replaced with a new
17
generation mix to include more renewable resources and distributed generation; and
18
conservation and demand management is emphasized in the journey towards a
19
greener and more environmentally sustainable province. This transformation is being
20
influenced to a large extent by the policies and priorities set by the Ontario
21
government as reflected in the GEGEA. In addition to the current FIT applications
22
under review by the OPA, many more applications are expected to be submitted in
23
the future. It is also anticipated that additional economic investments similar to the
24
Korean Consortium (Samsung) initiative will be pursued by the Government.
25
•
Aging Assets: Many of the transmission assets are aging and there are increasing
26
requirements to sustain the existing asset base in order to maintain reliable
27
performance. This will require new approaches to project prioritization to properly
28
assess the importance of aging asset issues relative to the Green Energy projects.
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 6 of 47
1
2
2) The life cycle management approach will create the need to sustain the transmission
3
asset base including the changing electricity system in Ontario.
4
challenges and demands on the transmission system but it will also present opportunities
5
for leadership and innovation to meet the needs of load and generator customers and
6
ensure continued safe, reliable and cost effective operation of the transmission system.
This will present
7
8
The Green projects will require Hydro One to adjust its Sustaining and Operations work
9
programs in the future to maintain and operate assets but the main integration of the
10
Green Energy projects will be required in the Transmission Development work area.
11
12
Impact on Transmission Development: Going forward, the transmission development
13
work program will, to a large extent, be influenced by the policies and priorities set by
14
the Ontario government as reflected in the GEGEA.
15
development will be driven by the need to connect and incorporate large numbers and
16
amounts of Renewable Energy Resources. Over the long-term, Hydro One investments
17
for incorporating potential renewable generation with the vast majority being remote
18
from the transmission grid and/or the Province’s load centres will focus on the following.
19
•
In particular, transmission
Projects to Increase Network Transfer Capability & Enable Connection of
20
Renewable Energy Facilities: The 20 projects identified in Schedule A of the
21
Minister’s letter of September 21, 2009 are crucial for connecting anticipated
22
renewable generation facilities and the Minister asked Hydro One to “immediately
23
proceed with the planning, development and implementation of the 20 Green
24
Transmission Projects, including seeking approvals for the upgrades as soon as there
25
is a reasonable basis to do so”.
26
•
Projects to Facilitate Generation Connections to the Distribution System: Schedule
27
B of the Minister’s letter identified a number of other investments that will be
28
required to remove constraints on the transmission system that currently limit the
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 7 of 47
1
amount of new Distributed Generation (DG) that can be accommodated. These
2
investments include the Hearn, Leaside and Manby TS upgrades, as well as building
3
enabling TSs, In-Line Circuit Breakers and other transmission facilities to enable
4
more DG to be connected downstream from TSs. These investments also cover the
5
development of standards, enhancements, modifications, and replacement of
6
protection and control equipment to allow mass deployment of Distributed Generators
7
on the Hydro One system.
8
9
Hydro One will need to be prepared to adapt to changes in plans brought about by the
10
GEGEA. The FIT program is essentially a customer driven program so that project
11
location and sizes are not predetermined. The economic development objectives of the
12
GEGEA will lead to commercial arrangements such as the Korean Consortium
13
(Samsung) agreement where in exchange for job creation and other economic benefits
14
some companies may be guaranteed capacity on the Transmission system and Hydro One
15
will have to accommodate these needs.
16
17
On a long-term basis, investments for incorporating potential renewable generation are
18
expected to be a significant component of the Transmission Development budget. As
19
explained above, the present capability of the transmission system is inadequate for the
20
incorporation and transfer of the additional capacity new generators will require to
21
connect to the bulk system and existing stations will require upgrades so that the
22
necessary transformation, voltage support and short-circuit capability is in place to
23
accommodate renewable generation and to ensure appropriate power quality for load
24
customers. These investments represent a major renovation of Ontario’s power system
25
and such unprecedented renewal of the transmission system is expected to result in a very
26
significant increase in the transmission network.
27
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 8 of 47
1
Ten Year Transmission Development Expenditure Levels
2
3
Projects driven by this Green Energy Plan will constitute a major portion of the
4
Transmission Development capital work program in the near term, 2010 – 2014 and over
5
the longer term, 2015 – 2020. Hydro One expects to spend $2.5B in the 2010 – 2014
6
timeframe and an additional $4.5B in the 2015 – 2020 period on these investments.
7
8
4.0
MAJOR GREEN PROJECTS
9
10
Descriptions of the Major Green Projects are provided in this section. Preliminary
11
Development Work is underway for the projects where the OPA has indicated there is the
12
highest indication of need. Table 1 below lists the projects from Schedule A of the
13
Minister’s Sept. 21, 2009 letter. The projects are grouped in three categories:
14
1. Projects where Preliminary Development Work is Underway
15
2. Projects where Development Work will begin once OPA Confirms Project Need
16
3. Projects where Development Work is Not Planned in the Test Years
17
18
The Item Number as per Schedule A of the Minister’s letter is indicated in column 3 of
19
the table. The development costs associated with these projects are provided in Section
20
8.0.
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 9 of 47
Table 1
1
2
Summary of Major Green Projects
3
4
Item
Item Number as per
Investment Description
#
Schedule A
Projects where Preliminary Development Work is Underway
1
East-West Tie Expansion
1
2
Transmission Reinforcement West of London
5
3
North-South Transmission Expansion
2&3
4
Manitoulin Island Enabler
8
5
Algoma x Sudbury Transmission Expansion
4
6
Goderich & Huron South Area Enablers
7&9
7
Northwest Transmission Reinforcement
14
Projects where Development Work will begin once OPA Confirms Project Need
8
9
10
11
12
13
14
15
Sudbury North - Pinard TS x Hanmer TS
Pembroke Area Enabler
Parry Sound Enabler
North Bay Enabler
Thunder Bay Enabler
St. Lawrence TS x Merivale TS (Cornwall x Ottawa)
Selby Junction x Belleville TS
Chenaux TS x Galetta Junction
18
10
11
12
13
15
16
17
Projects where Development Work is Not Planned in the Test Years
16
17
18
5
Longwood TS x Middleport TS
Bowmanville SS x GTA
Kenora x Thunder Bay Transmission Expansion
19
6
20
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 10 of 47
1
4.1
Projects where Development Work is Underway
2
3
1) East-West Tie Expansion
4
5
6
7
To provide an additional 300-500 MW of transfer capacity, Hydro One plans to build a
8
280 km 230 kV transmission line by widening an existing right-of-way. A 120 km
9
extension of the line to Lakehead is under consideration. In addition to facilitating the
10
transfer of new renewable generation from Northwestern Ontario to the load centres in
11
the province, this project is also expected to alleviate westbound congestion upon the
12
closure of the coal-generating facilities in the Northwest.
13
14
15
OM&A Development Work
Capital Expenditures
($ Millions)
($ Millions)
12.0
511.0
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 11 of 47
1
2) Transmission Reinforcement West of London (formerly London x Sarnia)
2
3
4
5
Hydro One will begin to identify transmission solutions that accommodate the significant
6
interest in wind generation development in the area west of London. The interest here
7
could exceed 1,000 MW, and based on the capacity of the existing system, it will be
8
necessary to build new transmission lines to incorporate it.
9
10
To provide an additional 1000 MW of transfer capacity, Hydro One plans to build three
11
single-circuit 500 kV or 230 kV transmission lines from:
12
1) Lambton TS to Longwood TS, 2) Lambton TS to Chatham SS, and 3) Chatham SS to
13
Longwood TS
14
This project is primarily aimed at facilitating the connection of renewable energy.
15
OM&A Development Work
Capital Expenditures
($ Millions)
($ Millions)
22.5
706.0
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 12 of 47
1
3) North-South Transmission Expansion
2
3
To provide an additional 1500-2000 MW of transfer capacity, Hydro One plans to build a
4
350 km 500 kV transmission line on an existing right-of-way from Sudbury to the GTA.
5
All the planned generation for Northern Ontario will need to be funnelled through this
6
North-South corridor, and the existing facilities are fully utilized. The additional capacity
7
created by other planned projects (e.g. SVCs) has already been allocated. Therefore, this
8
project is required for the development for any additional generation in Northern Ontario.
9
This project is primarily aimed at facilitating the connection of renewable energy.
10
11
OM&A Development Work
Capital Expenditures
($ Millions)
($ Millions)
18.5
884.0
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 13 of 47
1
4) Manitoulin Island Enabler
2
3
Manitoulin Island has the potential for a large amount of wind generation. Presently, the
4
transmission access to Manitoulin Island is provided by a single 115 kV, 50 km line from
5
Espanola TS (located between Algoma station near Blind River and Martindale station in
6
Sudbury) to Manitoulin TS (near Little Current). To provide an additional 400 MW of
7
transfer capacity, Hydro One plans to build a 80-120 km 230 kV transmission line. A
8
new switching station at Espanola is also needed. The actual length and terminal points
9
for the Enabler Line would be determined on the basis of the generation need as
10
articulated by the OPA and the EA Approval work. This project is aimed at facilitating
11
the connection of renewable energy.
12
13
OM&A Development Work
Capital Expenditures
($ Millions)
($ Millions)
7.5
169.0
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 14 of 47
1
5) Algoma x Sudbury Transmission Expansion
2
3
The Ontario Power Authority’s “Integrated Power System Plan” (Section E-3-2) has
4
identified 1,000 MW of wind generation in the Sault Ste. Marie/Algoma area. Major
5
transmission reinforcement will be required for this level of development. To meet this
6
need the IPSP had recommended a second 500 kV Hanmer TS to Mississagi transmission
7
line (approximately 210 km). The new line would be located on an existing Right of
8
Way. Because the EA Approval for the new line was obtained earlier (when the first 500
9
kV line, initially operated at 230kV, was built on the Right of Way), it is expected that
10
only a confirmation of the EA approval will be required. The new line would provide a
11
transfer capability of about 1,400 MW assuming that the existing companion line could
12
be converted to operation at 500 kV. These reinforcements can be coordinated to match
13
resource developments in the Sault/Algoma area. This project is aimed at facilitating the
14
connection of renewable energy.
15
16
OM&A Development Work
Capital Expenditures
($ Millions)
($ Millions)
5.5
431.6
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 15 of 47
1
6) Goderich and Huron South Area Enablers
2
3
4
The OPA has identified Goderich and Huron South as areas with substantial renewable
5
development potential. Based on the latest information received from the OPA regarding
6
the possible location of the renewable generator proponents, two main options are under
7
consideration.
8
currently serves Goderich TS to 230 kV line. The second involves the creation of a
9
500/230 kV autotransformer station from which 230 kV enabler lines will extend towards
10
the predominant clusters of renewable projects. This plan is subject to change as further
11
information is provided by the OPA and as the environmental assessment and preliminary
12
engineering work is carried out. Both of these are scalable and able to accommodate the
13
400 to 800 MW of projects expected in the area. These projects are aimed at facilitating
14
the connection of renewable energy.
The first involves the conversion of an existing 115 kV line which
15
16
OM&A Development Work
Capital Expenditures
($ Millions)
($ Millions)
6.0
164.0
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 16 of 47
1
7) Northwest Transmission Reinforcement (formerly Pickle Lake x Nipigon)
2
3
4
There is potential to develop 85 MW of economic hydroelectric generation on the Little
5
Jackfish River north of Lake Nipigon. In addition, there is potential development of up
6
to 278 MW of wind generation along the eastern shore of Lake Nipigon that will become
7
economical if transmission is available to connect them to the network. There is also
8
potential for approximately 580 MW of wind generation on the west side of the lake. The
9
Ontario Power Authority’s “Integrated Power System Plan” (Section E-3-7) had
10
identified these wind and hydro developments as preferred options to meet the 2025
11
Renewable Generation Target of the Ontario Minster of Energy’s directive to the OPA.
12
Ontario Power Generation is preparing plans for development of Little Jackfish
13
generation for coming in-service by the end of 2014.
14
15
In addition, there is growing demand from the mining industry, First Nations and other
16
remote communities in the Patricia District for additional supply. The additional supply
17
capacity in the district is required by the end of 2013 or earlier.
18
19
To enable the development of the renewable resources of Lake Nipigon and to reinforce
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 17 of 47
1
the transmission network in the Patricia District (and the East-West interties in the
2
future), a new single circuit 230 kV transmission line is proposed from Nipigon TS to
3
Little Jackfish and Crow River DS near Pickle Lake.
4
5
This project is aimed at both facilitating the connection of renewable energy and
6
facilitating economic development. This project also supports Northern Development.
7
8
OM&A Development Work
Capital Expenditures
($ Millions)
($ Millions)
21.7
399.5
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 18 of 47
1
2
4.2
Projects where Development Work will begin once OPA Confirms Project
Need
3
4
8) Sudbury North - Pinard TS x Hanmer TS
5
6
Most of the major hydroelectric generation opportunities in Ontario are located in an area
7
north of Sudbury. Currently, as much as 2,400 MW of hydroelectric generation
8
development has been committed or planned (in the long term) in this region. To
9
facilitate the development and integration of these generators into the Ontario power grid,
10
the need for an adequate transmission capacity north of Sudbury has been identified by
11
the Ontario Power Authority in the Integrated Power System Plan (Section E-3-3). The
12
reference plan calls for one new 370 km single circuit 500 kV transmission line from
13
Pinard TS to Hanmer TS in Sudbury. Additional lines may be required if extensive
14
Hydroelectric Generation development were to materialize in the north. This project is
15
aimed at facilitating the connection of renewable energy.
16
OM&A Development Work
Capital Expenditures
($ Millions)
($ Millions)
5.0
1,234.0
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 19 of 47
1
9) Pembroke Cluster Enabler
2
3
4
The OPA has identified 200 MW of renewable generation potential west of Barry’s Bay.
5
To accommodate this generation, a new 45 km 230 kV single-circuit line may be
6
required.
7
8
The actual length and terminal points for the Enabler Line would be determined on the
9
basis of FIT Applications received by the OPA and the EA Approval work. This project
10
is primarily aimed at facilitating the connection of renewable energy.
11
12
OM&A Development Work
Capital Expenditures
($ Millions)
($ Millions)
8.0
137.0
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 20 of 47
1
10) Parry Sound Enabler
2
3
4
An enabler line is identified for connecting a large pocket of renewable resources located
5
north of Parry Sound. A single-circuit 230 kV line, 75 km in length, would allow 240
6
MW of wind generation to be incorporated from the Parry Sound area. This line may use
7
the existing 500 kV corridor and connect to Parry sound TS.
8
9
The actual length and terminal points for the Enabler Line would be determined on the
10
basis of FIT Applications received by the OPA and the EA Approval work. This project
11
is aimed at the connection of renewable energy.
12
13
OM&A Development Work
Capital Expenditures
($ Millions)
($ Millions)
5.5
121.0
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 21 of 47
1
11) North Bay Enabler
2
3
4
An enabler line is identified for connecting a large pocket of renewable resources located
5
south of North Bay. A single-circuit 230 kV line, 54 km in length would allow 400 MW
6
of wind generation to be incorporated. The line would connect to Trout Lake TS.
7
8
The actual length and terminal points for the Enabler Line would be determined on the
9
basis of FIT Applications received by the OPA and the EA Approval work. This project
10
is aimed at facilitating the connection of renewable energy.
11
12
OM&A Development Work
Capital Expenditures
($ Millions)
($ Millions)
5.5
84.0
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 22 of 47
1
12) Thunder Bay Enabler
2
3
4
A new 80km single-circuit 230 kV line running west from the Thunder Bay area is
5
needed to incorporate 300 MW of renewable generation. The actual length and terminal
6
points for the Enabler Line would be determined on the basis of FIT Applications
7
received by the OPA and the EA Approval work. This project is aimed at facilitating the
8
connection of renewable energy.
9
10
OM&A Development Work
Capital Expenditures
($ Millions)
($ Millions)
12.0
119.0
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 23 of 47
1
13) St. Lawrence TS x Merivale TS (Cornwall x Ottawa)
2
3
4
Construction of an 82 km double circuit 230 kV line between Merivale TS and St
5
Lawrence TS is needed to incorporate 350 MW of renewable generation. This new
6
double circuit line will replace the existing 115kV transmission line (L1MB) and will be
7
located along the same ROW.
8
connection of renewable energy.
This project is primarily aimed at facilitating the
9
10
OM&A Development Work
Capital Expenditures
($ Millions)
($ Millions)
1.0
289.0
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 24 of 47
1
14) Selby Junction x Belleville TS
2
3
4
Construction of new 230kV line facilities to connect the 230kV circuits B23C/H23B at
5
Belleville TS with the X21 circuit at Selby Junction is planned in order to accommodate
6
renewable energy generation. This project is aimed at facilitating the connection of
7
renewable energy.
8
9
OM&A Development Work
Capital Expenditures
($ Millions)
($ Millions)
1.0
105.0
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 25 of 47
1
15) Chenaux TS x Galetta Junction
2
3
4
Construction of a 45km double circuit 230 kV line from Chenaux TS to line C27P at
5
Galetta Junction would allow for the incorporation of 200 MW of wind generation in the
6
Chenaux-Pembroke area. This new double circuit line would be along the Arnprior GS
7
line tap of C27P and involves the re-termination of the Arnprior GS tap to one of the
8
lines of the new circuit. This project is primarily aimed at facilitating the connection of
9
renewable energy.
10
11
12
OM&A Development Work
Capital Expenditures
($ Millions)
($ Millions)
1.0
104.0
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 26 of 47
1
4.3
Projects where Development Work is Not Planned in the Test Years
2
3
16) Longwood TS x Middleport TS
4
5
6
The West of London project previously described will enable renewable generation in
7
south western Ontario to be transmitted to London. To allow this generation to reach the
8
GTA, the transmission capability between London and Hamilton must be increased. In
9
order to increase power transfer capability from south western Ontario to the GTA, a new
10
single-circuit 500 kV line is required and, for the reference plan, is planned to stretch
11
from Buchanan TS to Middleport TS. The new right of way may be located next to the
12
existing Longwood x Nanticoke ROW. This project is primarily aimed at facilitating the
13
connection of renewable energy.
14
15
OM&A Development Work
Capital Expenditures
($ Millions)
($ Millions)
9.5
306.0
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 27 of 47
1
17) Bowmanville x GTA
2
3
4
The Ontario Power Generation’s (OPG) existing Darlington NGS site has been selected
5
as the location for the next new nuclear plant under the Government of Ontario nuclear
6
procurement project. Infrastructure Ontario has requested AECL, Areva NP and
7
Westinghouse to submit bids for the OPG New Nuclear at Darlington GS project.
8
Options for proposed unit sizes for a 2-unit station range from 1100 MW to 1600 MW
9
per unit. The transmission facilities required to incorporate the OPG New Nuclear at
10
Darlington GS into the network are as follows:
11
• a new 500 kV Bowmanville “B” SS (Switchyard), adjacent to existing Bowmanville SS
12
• a new double circuit line between Bowmanville “B” SS and Cherrywood TS (46 km)
13
14
OM&A Development Work
Capital Expenditures
($ Millions)
($ Millions)
11.5
167.0
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 28 of 47
1
18) Kenora x Thunder Bay Transmission Expansion
2
3
4
The reference plan includes the construction of a new 500km 230 kV double-circuit line
5
from Kenora to Thunder Bay with 3 new 230 kV breakers at each terminal station.
6
7
8
OM&A Development Work
Capital Expenditures
($ Millions)
($ Millions)
5.0
1,006
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 29 of 47
1
5.0
OTHER GREEN PROJECTS
5.1
Transmission Facilities to Enable Distribution Connected Generation &
2
3
4
Protection, Control and Telecom Investments
5
6
The Minister’s letter of September 21, 2009 also identified a number of Transmission
7
Projects in Schedule B of the letter. These Schedule B items comprise new projects on
8
the transmission system that will be required to accommodate increasing connections of
9
generators on the Province’s distribution systems. Other than the Hearn, Leaside and
10
Manby TS upgrades, these projects are not site specific at this time as they are intended
11
to respond to the uptake of the FIT program and will be required where high
12
concentrations of applications occur. These projects include new Enabling Transmission
13
Stations (TS’s), Static Var Compensators (SVC’s), In-Line Circuit Breakers and
14
Protection, Control and Telecom investments that will be required to provide sufficient
15
capacity on the transmission system to accommodate the FIT proponents. These projects
16
also include upgrading of Stations in the City of Toronto in order to enable generation to
17
be connected to the distribution system of Toronto Hydro.
18
19
These projects are listed in Table 2 below and show the capital expenditures required and
20
the target in-service years.
21
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 30 of 47
1
Table 2
2
Expenditures for Schedule B Projects
3
($Millions)
4
Capital
Item
Project
#
1
2
3
4
5
Expenditures
Target In-service
($ Millions)
Upgrade Short Circuit Capability of
Toronto Area Stations (Hearn TS,
Manby TS, Leaside TS)
Install 3 SVCs at 230kV +300/-100
MVAR (short term)
Install up to 7 Enabling TS
Install in-line circuit breakers at up
to 7 locations to enable generation
connections
Protection, Control and Telecom
Year
152.7
2012 – 2013
249
2013 - 2015
236
2013 - 2015
148
2012 - 2015
51.3
2009 – 2012
5
6
7
Item 1: Toronto Area Station Upgrades for Short Circuit Capability
8
The first of the Green Energy projects to be constructed and placed in service will be the
9
projects to Upgrade Short Circuit Capability at three Toronto area stations: Hearn TS,
10
Leaside TS and Manby TS. These projects will not require Section 92 applications.
11
Therefore, Hydro One is requesting approval of these projects as part of this application.
12
These projects are required to allow distributed generation in the City of Toronto to be
13
connected to the Transmission system and the Toronto Hydro (THESL) distribution
14
network.
15
16
17
The capital cost for these projects is provided in more detail in Table 3 below.
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 31 of 47
1
Table 3
2
Capital Costs of Toronto Short Circuit Upgrade Projects
3
($Millions)
4
Project
2010
2011
2012
Total
In Service
Hearn TS
3.0
54.6
27.0
84.9
2012
Leaside TS
2.0
13.5
21.9
37.4
2012
Manby TS
0
9.0
9.2
30.4*
2013
5.0
77.1
58.1
152.7
Total
5
* Total Project Cost as In-service date is 2013
6
7
The cost of these projects is also provided in Table 3 of Exhibit D1, Tab 3, Schedule 3,
8
Appendix A. Project descriptions (ISDs) of these projects are found in Exhibit D2, Tab
9
2, Schedule 3, see Items D11, D12 and D13.
10
11
Need for the Toronto Area Stations Projects
12
13
In order to enable connections of new green generation facilities, the short circuit
14
withstand ratings at these three Stations – Hearn SS, Leaside TS and Manby TS – need to
15
be increased. Development work to upgrade the Short Circuit capability at these stations
16
is underway. These upgrades will remove constraints whereby, as a result of relatively
17
lower, existing interrupting capability of circuit breakers and station structures, it is not
18
possible to connect medium and large sized generation to the distribution system owned
19
by Toronto Hydro.
20
21
22
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 32 of 47
1
Hearn TS
2
Hearn TS has a 115 kV switchyard with lines connecting to Leaside TS, Esplanade TS,
3
John TS, and the new Portlands Generation Station. Hearn is a critical element of supply
4
to the City of Toronto.
5
decommissioned Hearn Generation Station, and numerous components have reached the
6
end of their useful lives. Furthermore, the 21 existing 115 kV breakers are constraining
7
the connection of new distributed generation, and replacement breakers will be rated at
8
50 kA symmetrical. The new Hearn station is to be rebuilt adjacent to the existing Hearn
9
switchyard on lands to be acquired from Ontario Power Generation.
It was built in the early 1950s to connect the now-
10
11
Leaside TS
12
Leaside TS is a 230/115 kV autotransformer station that supplies the eastern section of
13
central Toronto. Replacing the existing 115 kV oil circuit breakers with breakers rated at
14
50 kA symmetrical will accommodate an additional 300 MVA of new generation on
15
Leaside’s 115 kV service area. This project involves the replacement of 28 oil circuit
16
breakers, which are 46 years old, and sections of the buswork.
17
18
Manby TS
19
Manby TS is a 230/115 kV autotransformer station supplying the western section of the
20
central area of the City of Toronto. The station has two 115 kV switchyards, Manby East
21
and Manby West, which are equipped with 115 kV oil circuit breakers. It is planned to
22
uprate the station fault current withstand capability to 50 kA. This will permit
23
incorporation of up to 300 MVA of new generation in the Manby 115 kV service area.
24
The proposed work covers replacement of 16 existing 115 kV oil breakers, which average
25
49 years old, at Manby TS with new SF6 breakers, uprating any limiting bus structure
26
components and replacement of other end of life equipment.
27
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 33 of 47
1
The OPA has recommended that Hydro One proceed with these projects in the supporting
2
evidence they have provided for this application. See Exhibit D1, Tab 3, Schedule 3,
3
Appendix B. Hydro One has also received a considerable amount of support for these
4
projects from organizations in the City of Toronto.
5
organizations are attached in Exhibit D1, Tab 3, Schedule 3, Appendix C.
Letters of support from these
6
7
Other Projects in Schedule B of the Minister’s Letter
8
9
Item 2: Install 3 Static Var Compensators
10
The Static Var Compensator (SVC) installations enable distributed generation by
11
providing voltage support so that the distributed generation can supply reverse power
12
through the transformer stations to which they are connected. The specific station
13
locations where these SVC installations will take place will be determined based on FIT
14
uptake and detailed system studies.
15
16
Item 3: Install up to 7 Enabling Transformer Stations in Areas of High FIT Interest
17
New transformer stations will be required to enable distributed generation in areas of
18
high FIT interest but limited transformer availability. The specific locations for these
19
stations will be determined based on FIT applications. New sites may be required.
20
21
Item 4: Install In-Line Circuit Breakers
22
From the perspective of system protection, there is a limit to the number of generating
23
stations or transformer stations (TS) feeding power back into the system that can be
24
tapped to high-voltage transmission circuits. Without carrying out detailed power system
25
studies, it is estimated that no more than two generating stations or reverse-feeding TS’s
26
can be connected to such circuits. When more than two such tap points are established on
27
the high-voltage circuits, then it becomes necessary to install high voltage in-line circuit
28
breakers in order to enable more generators to be connected to the circuits. The specific
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 34 of 47
1
locations where such installations would be installed will be determined on the basis of
2
FIT uptake and system studies.
3
4
Item 5 Protection, Control, & Telecom
5
Investments in Protection, Control and Telecom facilities will be required to maintain the
6
safety, reliability and integrity of the Transmission system while enabling connection of
7
distributed generation. These investments include:
8
•
transmission and distribution networks
9
10
•
Expansion of Hydro One’s Control Centre to monitor and operate its transmission and
rural distribution network and accommodate connected generation
11
12
Installation and/or upgrades to protection and control systems on Hydro One’s
•
Establishment of a telecom network needed to support enhanced protection, control &
operating capabilities
13
14
15
16
6.0
INFRASTRUCTURE INVESTMENT INCENTIVE APPROACH FOR
GREEN ENERGY PROJECTS
17
18
As explained in Exhibit A, Tab 11, Schedule 5, Hydro One is proposing a new approach
19
to cost recovery for the green energy projects, the “Accelerated Cost Recovery of CWIP”
20
mechanism. This proposed treatment is consistent with the methodology outlined by the
21
Board in its EB-2009-0152 “Report of the Board – The Regulatory Treatment of
22
Infrastructure Investment in connection with the Rate-regulated Activities of Distributors
23
and Transmitters in Ontario”, issued on January 15, 2010 (“the Report”) and in
24
discussions with stakeholders. One alternative approach suggested by the Board in EB-
25
2009-0152 was the accelerated cost recovery mechanism for construction work in
26
progress (“CWIP”) and pre-commercial expenses, and adjusting depreciation.
27
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 35 of 47
1
As discussed in Section 3.0 above, the projects included in this Green Energy and Green
2
Economy Plan represent a multibillion dollar investment in new transmission
3
infrastructure in Ontario.
4
Infrastructure Investment to address the unique challenges that have been created by new
5
Government policies and the GEGEA. As outlined in this Plan, Hydro One is responding
6
to an unprecedented level of investment in new facilities and an alternative funding
7
mechanism is appropriate.
The Board issued its report on Regulatory Treatment of
8
9
In addition to the large cost of the Plan, the green projects also have a high degree of risk
10
associated with them. This also supports the need for an alternative funding mechanism.
11
Building such large, complex and multi year projects will present very significant
12
challenges:
13
1) In almost all cases involving new line construction there will be the need for
14
consultation with First Nations & Metis communities and a number of issues to be
15
resolved around access to the land, financial settlements and compensation and
16
creation of jobs for the communities.
17
2) There will be major property acquisition issues. In the case of larger projects there
18
will be hundreds of landowners to negotiate with. Most landowners will want to
19
maximize the value of their land. This has been demonstrated in the Bruce to Milton
20
project where even after a very protracted negotiation period expropriation of many
21
properties is required.
22
3) There will be environmental risks with all of the projects. Most of the projects will
23
require Environmental Assessments and there are numerous issues associated with
24
potential contamination and land remediation, preservation of water bodies and wet
25
lands, protection of cultural and heritage sites and protection of endangered species.
26
4) There will be timing risks with all the green projects but especially the longer term
27
construction projects. Projects that are initiated under the current policy objectives of
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 36 of 47
1
the government may be subject to delay, changes or even cancellation if the policy
2
objectives change in future years.
3
4
Bruce to Milton and other recent line construction projects have been able to utilize
5
existing or widened corridors and yet the issues encountered as noted above have been
6
substantial. A number of the Green Energy projects will involve true Greenfield projects.
7
The property acquisition and Environmental risks will be significantly multiplied for
8
Greenfield projects.
9
projects will be more complicated and will take at least two years to complete. The
10
project development activities associated with these risks are explained in more detail in
11
Section 7.0 below.
It is expected that Environmental Assessments for Greenfield
12
13
The combination of extraordinary expenditure levels for the Green Energy projects and
14
the significant risk of delays or changes to the projects bring about the need for an
15
alternative funding mechanism.
16
17
The “Accelerated Cost Recovery of CWIP” mechanism will mitigate the rate impact of
18
the Green Energy Projects on customers by phasing in the costs of major transmission
19
projects over multiple years rather than all at once in the in-service year. It will provide
20
greater up-front regulatory predictability and will minimize the amount of interest that is
21
capitalized on major projects using the current funding approach. This latter benefit will
22
be magnified if project construction work is delayed due to factors outside of Hydro
23
One’s control.
24
25
For the majority of Green Energy projects in Schedule A of the Minister’s letter, Hydro
26
One is proposing to request the accelerated cost recovery of CWIP through a rate rider
27
for each project. This request will be made as part of the Section 92 application process.
28
Hydro One will propose to recover 100% of the CWIP following normal rate base
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 37 of 47
1
treatment.
This approach will result in the need for the project and the funding
2
mechanism being presented for approval at the same time.
3
4
Hydro One is planning capital spending in the test years for only two of the projects
5
identified in Schedule A of the Minister’s letter - the Northwest Transmission
6
Reinforcement Project (Pickle Lake to Nipigon) and the Sudbury Area to Algoma Area
7
project (Hanmer to Mississagi). The costs for these projects are included in Exhibit D1,
8
Tab 3, Schedule 3 and individual project descriptions (ISDs) for these projects are found
9
in Exhibit D2, Tab 2, Schedule 3 – see Items D34 and D35. The costs for these projects
10
are also provided in Table 4 below.
11
12
Table 4
13
Projects Proposed for Accelerated Cost Recovery of CWIP in Section 92 Hearings
14
($Millions)
15
Project
Northwest Transmission Reinforcement
Algoma x Sudbury Transmission
Expansion
Total
16
2008
2009
2010
2011a
4.5
2012a
16.9
5.7
Totalb
399
432
0
0
0
4.5
22.6
831
Notes: (a) Excludes AFUDC (b) Total cost including future years
17
18
As per the Board’s guidelines in EB-2009-0152, the Infrastructure Investment Report, it
19
is proposed that depreciation expenses will not be recovered until the individual projects
20
are formally declared in-service. Also, the rate riders will need to be adjusted annually to
21
recover the forecast financial carrying costs for the given year.
22
23
A complete description of the project costs and the associated amounts for accelerated
24
cost recovery of CWIP treatment will be provided in each Section 92 application.
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 38 of 47
1
7.0
DEVELOPMENT WORK FOR GREEN PROJECTS
2
3
Major transmission projects, including these Green Projects, will require First Nation and
4
Métis consultations, other community consultations and regulatory and environmental
5
approvals before construction can commence.
6
7
Development Work includes all activities, consultations, and approvals processes that
8
take place prior to the commencement of construction. This includes applications under
9
the OEB, Environmental Assessments through the MOE, and various other approvals.
10
Development Work consists of:
11
•
Regulatory
12
o OEB s.92, s.98, s.99 preparations
13
o Hearings and Intervenors’ costs
14
o Legal advice
15
o Other tribunals, e.g. NEC
16
•
Environmental Assessments
17
o Development of reference corridor
18
o Development of Terms of Reference
19
o Field Studies
20
o Preparation of Environmental report
21
•
Planning, Scoping, Estimating
22
o Identification and assessment of alternatives
23
o Development of detailed reference plan
24
o Preparation of planning specifications
25
o Preparation of project cost estimates
26
•
Consultation
27
o FN & Métis (including capacity funding)
28
o Communities and Landowners
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 39 of 47
o Municipal and Provincial representatives
1
2
•
Real Estate
3
o Title searches
4
o Investigative surveys
5
6
Additional details about these components are described below.
7
8
7.1
Process and Timelines for Development Work
9
10
Development Work for large transmission projects can begin as much as six years prior
11
to the desired in-service date to ensure that all the approvals and property rights are
12
acquired. The Development Work for major projects typically takes at least five years,
13
and construction is typically expected to take a further one to three years, and possibly
14
more for larger complex projects.
15
complexity of the project. The need for the project is confirmed by the time a Section 92
16
application is submitted, which is approximately 1.5 years after the project is launched.
17
The diagram below highlights the various phases of the planning and construction
18
timeline.
19
Construction time will depend on the size and
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 40 of 47
1
2
3
The Development Work for all transmission lines projects in this Plan will be carried out
4
according to existing processes. Thus, while the Plan identifies the broad-based
5
conceptual strategy for incorporating renewable generation into the transmission system
6
across the province, the transmission lines projects will be brought before the Ontario
7
Energy Board individually for review and approval through the s.92 applications for
8
leave to construct, and Environmental Assessment approvals will also be sought where
9
required.
10
11
7.2
Strategy
12
13
In his letter of September 21, 2009, the Minister asked Hydro One to immediately
14
proceed with the planning, development, and implementation of 20 Green Projects. To
15
meet this request, Hydro One’s strategy is to:
16
1. Consult with the OPA on the need, timing, and conceptual plans for all 20
17
transmission projects.
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 41 of 47
1
2. Begin the preliminary development work for projects to identify potential variables
2
that will shape the environmental, property, design and construction profiles and give
3
consideration to the potentially affected First Nations and Métis communities.
4
3. Begin the formal Development Work on projects based on the results of the ECT or
5
as identified by the OPA or the Government.
6
environmental feasibility studies; detailing the real estate profiles, developing
7
technical alternatives; initiating pre-public consultations with potentially affected
8
First Nations and Métis communities, municipalities, government ministries,
9
agencies, and other stakeholders; holding Public Information Centers in local
10
This work includes: conducting
communities; and conducting the environmental assessment work.
11
12
This strategy allows for timely completion of development work for the projects with the
13
highest probability of realization based on information presently available. It also allows
14
for the staggering of the development work and more efficient use of resources. If the
15
level of need dissipates in the future, there is a risk that some funds are spent on projects
16
that are not required to be constructed by the original timelines. However, in the majority
17
of cases this work will not be wasted as it will be used at a later time when the need does
18
materialize. This risk is further mitigated since the chance of this happening would be
19
confined to only the Green Projects with the highest need and not the entire list of 20
20
Green Projects, and uncertainty about the need is managed through close and regular
21
consultation with the OPA. Furthermore, the Board will have an opportunity to review
22
and test the prudence of these projects when Hydro One files the Section 92 applications
23
for Leave to Construct and when the company files the required Project Completion
24
Reports.
25
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 42 of 47
1
7.3
Some Major Elements of Development Work
2
3
First Nations and Métis Relations
4
5
The Supreme Court of Canada has found that the Crown has a duty to consult before
6
making a decision where Aboriginal and/or treaty rights may be potentially affected.
7
The Crown may delegate procedural aspects of its duty to consult aboriginal peoples to
8
the proponent for a project.
9
10
There are several overarching principles that guide Hydro One’s consultation activities
11
with First Nations & Métis communities, such as ensuring a consistent and thorough
12
approach to consultation and having respect for traditional practices, heritage sites, socio-
13
economic issues, the environment and traditional knowledge.
14
develop relationships of mutual respect and trust. Such relationships facilitate the two-
15
way exchange of information between the parties respecting any project plans, addressing
16
concerns to the extent possible and ensuring on-going dialogue about the plans and their
17
potential implications and benefits.
18
opportunity to strengthen relationships with First Nations & Métis communities. At all
19
times, Hydro One aims to ensure an open, ongoing dialogue and aims to seek joint
20
resolution of issues that arise wherever reasonably possible.
Hydro One aims to
Hydro One also sees the consultation as an
21
22
First Nations and Métis communities may have limited resources to effectively engage in
23
consultation and Hydro One considers providing capacity funding to communities to
24
allow them to adequately participate. This funding can cover costs such as wages for
25
liaison staff, travel and meeting attendance, external legal and technical advice, as well as
26
hosting community-wide information sessions.
27
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 43 of 47
1
In addition to capacity funding, Hydro One must consider if, and what, mitigation,
2
accommodation or benefits might be provided to First Nations and Métis communities
3
whose rights are potentially impacted by its projects. Such benefits or accommodation
4
might be defined in a Community Benefits Agreement and can include items such as
5
funding, employment, training, business partnerships, etc.
6
7
Environment
8
9
All Transmission Projects are subject to Environmental Assessment Act approval. The
10
requirements of the Act are very broad and extend beyond prediction of environmental
11
effects and mitigation or elimination of those effects.
12
(“EA”) process must establish the need for the project, consider possible alternatives to
13
the undertaking, and identify alternative methods of carrying out the undertaking.
14
Consultation with all affected parties is a key component of the process. Another key
15
feature is the broad definition of environment in the legislation. Environment includes
16
not only the natural environment but also the socio-economic environment and use of
17
resources.
The Environmental Assessment
18
19
All project concerns become EA issues, and the process is the focal point of public,
20
regulatory and Aboriginal community opposition. The EA and OEB processes share
21
some common requirements (e.g. undertaking to be approved, project need, alternatives
22
considered, public notification/consultation) and consequently the respective timing of
23
the approvals has strategic implications.
24
25
1. The EA process has two stages: approval of a Terms of Reference which describes
26
the scope of the process to follow (e.g., route selection, effects prediction,
27
consultation, etc.) and the Environmental Assessment, which presents the result of the
28
process.
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 44 of 47
1
2. The EA document is reviewed first by a multi-agency government team which
2
produces a review of the assessment. A public review period in which comments on
3
the EA and the government review can be submitted in addition to recommendations
4
for a public hearing follows.
5
6
Real Estate
7
8
For new transmission projects, Hydro One will require various forms of land tenure real
9
estate rights for its facilities depending on whether the lands are privately owned, Crown
10
lands, First Nation Reserves, or rail/pipeline/3rd party interests. Land acquisition could
11
entail confirming and/or renegotiating existing rights or acquiring new rights and
12
properties from private property owners before project construction begins. The timeline
13
for acquiring the necessary real estate rights for major transmission projects can be
14
lengthy, and may involve the more formal, legislated expropriation process. This can
15
have a significant impact on project schedule and cost.
16
17
In addition, accurate identification of property owners affected by major transmission
18
projects is necessary to ensure that notification requirements associated with regulatory
19
approval processes (i.e., Ontario Energy Board Leave to Construct – “Section 92”) are
20
met. Inaccuracies in identifying affected property owners can result in significant delays
21
to the regulatory approval processes.
22
23
8.0
DEFERRAL ACCOUNT FOR OM&A DEVELOPMENT COSTS
24
25
In the 2008-0272 Hydro One Networks’ 2009-2010 Transmission Revenue Requirement
26
Decision with Reasons issued on May 28, 2009, the OEB approved the establishment of
27
an “IPSP and Other Preliminary Planning Costs Account”. This deferral account is used
28
to record the Development Costs associated with major projects. Since then, the GEGEA
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 45 of 47
1
has received Royal Assent. Also, on September 21, 2009, the Minister of Energy and
2
Infrastructure sent a letter to Hydro One requesting that it immediately proceed with the
3
planning, development and implementation of a number of transmission and distribution
4
projects which allow the grid to accommodate additional renewable generation as per the
5
policy objectives of the GEGEA, as well as seek the necessary approvals for these
6
projects.
7
8
On December 3 and December 15, 2009 Hydro One submitted requests to the Ontario
9
Energy Board to amend the list of projects associated with the “IPSP and Other
10
Preliminary Planning Costs Account”.
This request for the inclusion of additional
11
projects was driven by the GEGEA and the need to commence work on these additional
12
projects to meet the target in-service dates identified in the Minister’s letter. The Board
13
initiated proceeding EB-2009-0416, and on March 25, 2010 the Board issued its Decision
14
approving the inclusion of the additional projects in the deferral account.
15
16
The additional projects included in the deferral account align with Schedule A of the
17
Minister’s Sept. 21, 2009 letter. There will be varying levels of development work in the
18
test years, 2011 and 2012 for seventeen of the twenty projects in Schedule A of the letter.
19
Two of the projects, number 19, Longwood TS x Middleport TS (formerly London to
20
Hamilton Area in the Minister’s letter) and number 20, Kenora to Thunder Bay
21
Transmission Expansion are not included as they are too long term to start development
22
work within the test year period. One other project, number 6, Bowmanville SS to GTA
23
is now considered longer term in nature and while it is one of the projects where early
24
development work was started in prior years there are no dollars in the test years for
25
development work.
26
27
Hydro One’s planned expenditures on the OM&A Development projects are provided in
28
Table 5 below. A similar table of OM&A development expenditures is found in Table 1
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 46 of 47
1
of Exhibit C1, Tab 2, Schedule 4. The table in that exhibit includes the projects below as
2
well as other OM&A development work.
3
Table 5
4
5
6
Summary of Development Work for Major Green Projects in Bridge and Test Years
7
Ite
m
#
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
8
9
Cash Flow ($ Millions)
Investment Description
2010
2011
2012
Total
East-West Tie Expansion (Item #1)
North-South Transmission Expansion
(Items #2/3)
Algoma x Sudbury Transmission
Expansion (Item #4)
Transmission Reinforcement West of
London (Item #5)
Goderich Area Enabler (Item #7)
Manitoulin Island Enabler (Item #8)
Huron South Enabler (Item #9)
Pembroke Area Enabler (Item #10)
Parry Sound Enabler (Item #11)
North Bay Enabler (Item #12)
Thunder Bay Enabler (Item #13)
Northwest Transmission Reinforcement
(Item #14)
St. Lawrence TS x Merivale TS (Cornwall
x Ottawa) (Item #15)
Selby Junction x Belleville TS (Item #16)
Chenaux TS x Galetta Junction (Item #17)
Sudbury North - Pinard TS x Hanmer TS
(Item #18)
0.7
4.1
3.0
12.0
1.5
4.5
3.0
18.5
0.6
2.0
3.0
5.5
0.7
9.0
10.0
22.5
0.4
0.5
0
0
0
0
0
1.0
1.0
0
1.5
0.5
0.5
1.0
2.5
3.0
0.5
3.0
2.5
2.2
4.0
5.0
7.5
1.0
8.0
5.5
5.5
12.0
3.0
10.5
7.0
21.7
0
0
0.5
1.0
0
0
0
0
0.5
0.5
1.0
1.0
0
0.1
1.5
5.0
Total Costs
7.4
35.7
46.7
132.7
Note 1: “Total” costs include cash flows, if any, in years before 2011 and after 2012.
Filed: May 19, 2010
EB-2010-0002
Exhibit A
Tab 11
Schedule 4
Page 47 of 47
1
Inclusion of a Rate Rider for Recovery of the OM&A Cost in the Deferral Account
2
3
As discussed in Exhibit F1, Tab 1, Schedule 2, Hydro One is requesting recovery of the
4
2009 OM&A development costs of $1.9 million ($2 million with interest). Hydro One is
5
not requesting recovery of the other OM&A costs in this deferral account at this time.
6
However, given the materiality of these development costs, currently projected at $160
7
million in total (see Exhibit C1, Tab 2, Schedule 4) Hydro One is considering the need
8
for a mechanism to recover these costs as incurred and might propose a rate rider
9
mechanism. The rider mechanism would recover the costs in the deferral account each
10
year to mitigate the sudden large rate impact of the deferral account recovery.
Filed: May 19, 2010
EB-2010-0002
Exhibit A-11-4
Appendix A
Page 1 of 5
-2-
1. Immediately proceed with the planning, development and implementation of
Transmission Projects outlined in the attached Schedule A, including seeking approvals
for the upgrades as soon as there is a reasonable basis to do so.
2. Collaborate with the OPA in defining the scope of work, including termination points,
target capacity, number of lines, technical options and sequencing necessary for the
Transmission Projects, as well as collaborating with the Independent Electricity System
Operator on System Impact Assessments and reliability impacts.
3. Develop and implement smart grid infrastructure in accordance with upcoming
. government policy, including establishing novel ways of managing network
infrastructure for renewables more efficiently.
4. Given the magnitude of work required to complete the Transmission Projects:
a. Identify the commercially reasonable opportunities for entering into partnership
arrangements with qualified third parties/partners for the execution of the
Projects;
b. Work with the Shareholder to identify commercially reasonable criteria that will
be used to select qualified third parties/partners;
c. Use best efforts to enter into those commercially reasonable arrangements; and,
d. Identify projects as appropriate where the planning, development and
implementation of the project would be better accomplished by a qualified third
party oilier than Hydro One.
5. Provide opportunities for participation in the projects by potentially-affected Aboriginal
peoples.
6. Immediately proceed with the planning, development and implementation of upgrades
to enable distribution system connected generation, as outlined in the attached Schedule
B, including collaborating with the OPA and the Independent Electricity System
Operator in defining the scope of work necessary for the transmission facilities to enable
distribution system connected generation.
7. Begin planning and preliminary development to explore and preserve options for
longer-term, high-capacity, transmission link between Thunder Bay and the Greater
Toronto Area, including associated collaboration with the OPA for planning.
8. Subject to Crown oversight, engage in consultations with and, where appropriate,
accommodate Aboriginal peoples respecting their section 35 rights of the Canadian
Constitution Act, potentially affected by transmission and distribution projects listed in the
attached Schedules.
.../cont'd
-3-
To be clear, I am seeking your cooperation on these matters as a key enabler for the feed-in tariff
program to be implemented under the GEA and in order to establish a more modern and
reinforced electricity grid in Ontario. In no way does my request relate to the implem entati on
or methods used to carry out the work described in this letter, including following approp riate
cons u lta tion and approvals processes. In light of that, I would expect that H ydro One will
develop a comp rehensive implementation plan to achi eve these objectives.
Furthe rmore, in order to be informed about Hydro One's progress toward implementing and
meeting these objectives, and in keeping wi th the purpose of th e Memorandum of Ag reeme n t
between Hydro One and the Shareholder, I request that Hydro One report back to m e on a
semi-ann ual basis on planning, development and implementation activities undertaken, and
progress made in connection with Transmission and Distribution Projects that will enable the
feed-in-tariff program. I would appreciate receiving a first report by no later than the end of
Nove mber 2009.
I am ap preciative of Hydro One's continued leadership in moving towards Ontario's green
ene rgy future and look forward to seeing your progress in meeting the government's objectives
on transmission and dis tribution system expansio n.
On behalf of the Hydro One Board, would you please confirm your understanding of the above,
and yo ur concurrence with all that is contemplated, by signing in the space pr ovided below.
Thank yo u for your prompt attention to these matters.
Since re ly,
I concur,
~mes Arne tt
Chair of the Board, Hydro One
Enclosures
Schedule A - Transmission Projects
Item #
Project
Key Driver
Target
In-Service Year*
Core Transmission (Bulk transmission upgrades)
1
East-West Tie: Nipigon x Wawa (230 kV)
Bulk Transmission Capability for FIT program
2015
2
North-South Tie: Sudbury Area x Barrie (500 kV)
Bulk Transmission Capability for FIT program
2015
3
Barrie x GTA (500 kV)
Bulk Transmission Capability for FIT program
2015
4
Sudbury Area x Algoma Area (Mississagi Transformer Station, 70km east of Sault Ste. Marie) (500 kV)
Bulk Transmission Capability for FIT program
2014
5
London Area x Sarnia (500 kV or 230 kV)
Bulk Transmission Capability for FIT program
2016
6
Bowmanville x GTA (500 kV)
Bulk Transmission Capability for reliability and FIT program
2016
Enabling Transmission (Local enabler connection lines for renewable clusters)
7
Goderich Enabler
Connections in anticipation of high renewables demand
2013
8
Manitoulin Island Enabler
Connections in anticipation of high renewables demand
2014
9
Huron South Enabler (Wanstead Transformer Station)
Connections in anticipation of high renewables demand
2016
10
Pembroke Enabler
Connections in anticipation of high renewables demand
2014
11
Parry Sound Enabler
Connections in anticipation of high renewables demand
2015
12
North Bay Enabler and 230 kV Line Upgrade
Connections in anticipation of high renewables demand
2015
13
Thunder Bay Enabler
Connections in anticipation of high renewables demand
2015
Regional Transmission (Regional transmission lines for renewables)
14
Pickle Lake x Nipigon
Renewables, Reliability, and Load Growth
2013
15
Cornwall x Ottawa
Renewables and load growth
2015
16
Belleville x Napanee (Selby Junction)
Renewables and load growth
2014
17
Chenaux x Arnprior Area (Galetta Junction)
Renewables and reliability
2014
Longer-Term (Post-2016)
18
Sudbury North (500 kV)
Bulk Transmission Capability for FIT program
2017
19
London x Hamilton Area (500 kV)
Bulk Transmission Capability for FIT program
2020
20
Kenora x Thunder Bay
Bulk Transmission Capability for FIT program
2020
* Scope, sequencing and details of implementation subject to detailed Implementation Plan
Schedule B - Projects to Enable Distribution System Connected Generation
Item #
Project
Target
In-Service Year*
Transmission Facilities to Enable Distribution-connected Generation
1
Install 3 Static Var Compensators in Areas of high FIT Uptake
2012-2014
2
Install up to 7 Enabling Transformer Stations in Areas of High FIT Uptake
2012-2015
3
Upgrade Short Circuit Capability of Toronto Area Stations (Hearn TS, Manby TS, Leaside TS)
4
Install in-line Circuit Breakers at up to 7 Locations to Enable Generation Connections
2012
2012-2015
Distribution
5
Targeted Dx Enhancements to Support Distributed Generation
-10 New Distribution Feeders (in areas of high FIT uptake)
-Other Minor Investments
2009-2012
Protection, Control, and Telecom (enabling distributed generation)
6
DG Connection Cost Reduction
-Wide Area Telecommunication Infrastructure
-Wide Area Island Detection
-Transmission Protection Change for Tap-Connected Generation
-Stop-Gap Wireless Remote Trip
-GPRS (Cellular) Telemetry
-Pulse-signalling Island Detection
-OGCC System Changes
7
Protection
-Feeder Protection Replacements
-Telecom to In-Line Reclosers
-TS Bus Protection Replacements
8
TS Capacity Expansion
-Generation Trip and Block Scheme
-Automated Generation Dispatch System
-Transfer Protection Replacements
-Tapchanger Control Upgrades
-OGCC System Changes
9
Product Quality
-Feeder Voltage Regulator Replacement
-OGCC System Changes
10
Bulk System Reliability
-Distribution Station SCADA and Protection Upgrades
-OGCC System Changes
-Load Rejection Systems Modifications
* Scope, sequencing and details of implementation subject to detailed Implementation Plan
2009-2012