TRANSMISSION GREEN ENERGY PLAN

Transcription

1 Filed: May, 0 EB-0-00 Tab Schedule Page of TRANSMISSION GREEN ENERGY PLAN INDEX 0 SECTION.0 SECTION.0 SECTION.0 SECTION.0 HYDRO ONE S GREEN ENERGY PLAN PROJECTS TO FACILITATE GREEN ENERGY IN EB PROJECTS TO FACILITATE GREEN ENERGY IN THIS RATE SUBMISSION & PROJECTS CONNECTING TO THE TRANSMISSION SYSTEM RECOVERY OF DEVELOPMENT COSTS FOR EARLIER GREEN ENERGY PROJECTS

2 Filed: May, 0 EB-0-00 Tab Schedule Page of.0 HYDRO ONE S GREEN ENERGY PLAN The Hydro One Transmission Green Energy Plan for 0 and 0 continues to have significant investments for the integration of renewable generation in the Province of Ontario that is consistent with the Green Energy and Green Economy Act, 00 ( GEGEA ) and government policies. It reflects the transmission needs of the Ontario Government s Long Term Energy Plan ( LTEP ) and is based on ongoing planning work by Hydro One, the OPA and the Ministry of Energy and Infrastructure related to renewable initiatives. 0 A significant number of transmission projects are included in the Development Capital portion of this application (Exhibit D, Tab, Schedule ) to provide increased capacity to facilitate further planned renewable resources or to connect renewable projects. This exhibit provides an overview of these projects which form the Hydro One Green Energy Plan for this rate submission.. Background 0 The Green Energy Plan in Proceeding EB outlined Hydro One s strategy to implement the Government of Ontario s policy objectives in the GEGEA and more specifically a letter dated September, 00 from the Minister of Energy and Infrastructure to Hydro One, which is attached in Appendix A to this exhibit. The letter instructed Hydro One to immediately proceed with the planning, development and implementation of 0 large transmission projects outlined in Schedule A and also a number of shorter term Schedule B projects to facilitate distributed generation including the Hearn SS, Leaside TS and Manby TS upgrades, In-Line Circuit Breakers, Static Var Compensators ( SVC s ), enabling transformer stations, and Protection and Control ( P&C ) upgrades.

3 Filed: May, 0 EB-0-00 Tab Schedule Page of 0 On May, 00 the Minister of Energy and Infrastructure sent a letter to Hydro One (attached in Appendix B to this exhibit) instructing the company to reassess its pending transmission rate application in light of the government s efforts at cost restraint and to focus the forthcoming transmission rate application on projects that are critical to the connection of renewable generation projects that have been identified by the Ontario Power Authority as part of the government s green energy agenda. Further, on May, 00 the Minister also wrote to the OPA (also attached in Appendix B to this exhibit) and instructed it to prepare an updated transmission expansion plan that would replace the September, 00 instruction to Hydro One and address the needs of the Feed In Tariff ( FIT ) program and the Korean Consortium. In response to these letters, Hydro One suspended all development work on the 0 Schedule A projects in May, 00. Work continued on the Schedule B projects that were approved by the Board in the EB Decision and Order..0 PROJECTS TO FACILITATE GREEN ENERGY IN EB In the EB Decision, the Board approved several projects which at the time were also included in the list of Schedule B projects referred to above. These investments included the Hearn SS, Leaside TS and Manby TS upgrades, as well as two In-Line Circuit Breakers and P&C Facilities to Enable Distributed Generation. However, the Decision did not allow P&C upgrades for the purpose of enabling distribution connected projects to be recovered from rates. A summary of the previously approved projects is outlined below in Sections. to.. There were also several projects in the list of Schedule B projects in the previous rate submission that had capital spending in the test years, but would not be in-service in the 0-0 test years. These investments included two Enabling Transmission Stations, four In-Line Circuit Breakers, and a SVC to accommodate potential distributed

4 Filed: May, 0 EB-0-00 Tab Schedule Page of generation from the FIT program. In the EB Decision, the Board did not provide any guidance to the company with respect to these projects. However, the Board did state that the decision to withhold project approval does not inhibit the company from doing whatever it considers to be prudent in preparation for these projects; with the disclaimer that the company may need to bring the projects back to the Board for approval once more robust evidence of need is available. As Hydro One, IESO and OPA studies have not identified a specific need for any of these projects to date; no capital spending has been incurred for these projects and no investments have been included in this rate submission. 0. Projects to Facilitate Generation Connections to the Toronto Hydro System 0 In order to enable connections of new renewable and high efficiency generation facilities, the short circuit capabilities at three Stations in Toronto Hearn SS, Leaside TS and Manby TS needed to be increased. The short circuit levels at these stations are almost near the equipment limits and currently permit only a very limited amount of distributed small scale generation to be connected. Work to upgrade the short circuit capability at these stations is underway. This work involves replacing the end-of-life facilities at Hearn SS with a new switchyard, and largely upgrading the breakers at Leaside TS and Manby TS for higher short circuit operation. Further details of these projects are provided in Exhibit D, Tab, Schedule and in Exhibit D, Tab, Schedule, ISD s # D, D, D. Once this work is completed it will be possible to connect not only significantly more small scale and larger size distributed generation but also medium and large sized transmission connected generation to the central and downtown areas of Toronto. Since the last transmission rate application, both costs and timing of these projects have been updated as shown in Exhibit D, Tab, Schedule, Appendix A, Table. Overall, the costs for the three stations are slightly lower than estimated in the previous

5 Updated: August, 0 EB-0-00 Tab Schedule Page of transmission rate application (EB ,, Tab, Schedule, Table ). Estimates provided at the time of the last rate submission were budgetary and only a limited amount of preliminary engineering had been completed. Since that time detailed engineering including major tenders for equipment and major land acquisition has been completed. 0 The current project cost for Hearn SS is higher due to increased costs for the turn-key GIS station following the tendering process and increased costs for P&C facilities. The delayed in-service date for Hearn SS from the initial forecast of December 0 is due to a one year delay in acquiring property for the new switchyard. It was initially anticipated that the land acquisition could be completed by late Fall 00; however, property purchase negotiations took longer than expected and the required property could not be secured until late October 0. 0 The current project costs for both Leaside TS and Manby TS are lower as a result of detailed engineering work which determined that a portion of the P&C facilities did not require modifications at this time and replacement could be deferred. The in-service dates for Leaside TS and Manby TS are delayed from the initial in-service dates of December 0 and December 0, respectively due to difficulty in obtaining outages in the City of Toronto to stage the station upgrade work. The revised target in-service dates are now Q 0 for both Leaside TS and Manby TS.. In-Line Circuit Breaker Projects From the perspective of system protection, there is a limit to the number of generating stations or transformer stations feeding power back into the system that can be tapped to high-voltage transmission circuits. Detailed power system studies and P&C analysis are required to establish how many such stations can be tapped to any particular transmission

6 Updated: August, 0 EB-0-00 Tab Schedule Page of circuit. Various factors including size, type, station design and the connection location of the generation as well as the electrical characteristics of the local system can affect the number of stations that can be tapped. In cases where a generator cannot be connected via a simple tapped arrangement, additional high voltage facilities are required to provide switching and to sectionalize (or divide) the existing circuit into more than one section. Appropriate protection can then be provided for each section. 0 For connections to a single circuit that requires sectionalizing, the minimal facilities to achieve this involve much more than in-line circuit breakers. New station infrastructure is required to house and support these breakers including bus work, a building for relay and communication facilities, local AC power supply, grounding, fencing, environmental mitigation and even an access road. 0 In the previous rate submission, Hydro One proposed that likely two in-line breaker facilities would be required by 0 based on the information available for the projects that were awarded FIT contracts in spring 00. Following the connection assessments of many of these projects, it was confirmed that two generation projects - Summerhaven and Sandusk (formerly referred to as Port Dover) - required in-line breakers by 0. These projects were expected to be completed by the end of 0; however, approvals and other delays experienced by the generator proponents have delayed the completion of the in-line breaker stations to 0. In the EB Decision, the Board approved two In-line Circuit Breaker projects at a preliminary estimated net cost of $0.M each. The expected gross cost for the inline breakers for the Summerhaven and Sandusk wind farm projects are $. million and $. million respectively. The current net costs for the Summerhaven and Sandusk projects are $0. and $. respectively. These costs are based on detailed engineering and reflect the scope of work identified by the IESO s System Impact Assessment and

7 Updated: August, 0 EB-0-00 Tab Schedule Page of Hydro One s Customer Impact Assessment.. P&C Upgrades to Enable Distribution Connected Generation Two major Protection and Control investments were identified at Transmission Stations to allow the connection and efficient ongoing operation of generation to distribution systems: 0. Station Protection Upgrades for Distributed Generation This identified the various protection and control upgrades at the transmission stations which are required to ensure the reliability of supply, the protection of transmission assets and safety.. Enhanced Transfer Trip Facilities This identified the need for enhanced transfer tip signaling facilities at Transmission Stations to allow transmission forced and planned outages to proceed without requiring generation connected to the distribution system to be curtailed or shut down. 0 In the Decision and Order in proceeding EB , the Board approved the Station Protection Upgrades and Transfer Trip Facilities investments. However, the Board concluded costs should not be recovered from rates and that the Transmission System Code prescribed user-pay approach for such facilities is appropriate. The Station Protection Upgrades investments are essential to allow generators to connect and work is proceeding on these investments. Administrative systems are being put into place to obtain fair recovery from the generators. See Section.. in Exhibit D, Tab, Schedule for more details. The Enhanced Transfer Trip Facilities are not essential to allow generators to connect and this work has been delayed until a fair mechanism can be designed to allow all generators

8 Updated: August, 0 EB-0-00 Tab Schedule Page of that benefit from their implementation to determine if they wish to contribute to the cost. A number of generators have begun to ask for these facilities as the cost of lost revenue will quickly pay-back their share of the implementation cost. As with the Station Protection Upgrades, these facilities will benefit generators in different groups. Enhanced feeder transfer trip facilities will benefit all generators connected to a back-to-back feeder pair during outages to the station bus or feeder breakers. Enhanced wide-area transfer trip facilities will benefit all generators connecting to a transmission station or transmission line. Mechanisms are being examined to reach out to all generators that will benefit from the installation of these facilities and determine equitable sharing of cost. 0.0 PROJECTS TO FACILITATE GREEN ENERGY In addition to the projects discussed above, this section describes the projects in the current rate submission which will facilitate further development of green energy. Table summarizes the related investments, their costs and the level of renewable generation that they potentially facilitate. These projects collectively allow for the connection of approximately MW of renewable energy.

9 Updated: August, 0 EB-0-00 Tab Schedule Page of Item # Project Table Gross ($M) Net ($M) Renewable Generation Facilitated (MW) Up to 00 Reconductor the Lambton TS to Longwood TS 0kV Circuits Installation of SVC at Milton SS FIT Renewable Generation Connections 0.* 0.* 000 Non-FIT Renewable Generation Connections.* 0.* 0 Allanburg TS: Upgrade Short Circuit Capability.0.0 Up to 0 Hawthorne TS: Upgrade Short Circuit Capability.. Up to 00 Protection and Control Upgrades to Enable Generation Connections to Distribution Systems Protection and Control Upgrades for the Consequences of Generation already connected to Distribution Systems * Estimates of capital expenditure for 0 and 0 only Up to Item # and # reflect two of the three priority projects in the Government of Ontario s LTEP that were designated to Hydro One. Hydro One received letters from the OPA to proceed with the re-conductoring work on the existing Longwood to Lambton circuits on June 0, 0 (attached in Appendix D to Exhibit D, Tab, Schedule ) and to proceed with the addition of an SVC at Milton SS on October, 0 and further supporting evidence in March, 0 (attached in Appendix C to Exhibit D, Tab, Schedule ). Further details of these projects are provided in Table of Exhibit D, Tab, Schedule, Appendix A and ISD s # D and #D at Exhibit D, Tab, Schedule. The third priority project in the LTEP involves a new transmission line west of the London area. Hydro One understands that further studies by the OPA are required to establish the scope and requirements of the new line. For the new line project, only minor expenditures of $ million or less have been included in the test years to conduct studies in support of the OPA, perform conceptual level engineering and initiate preliminary approvals work.

10 Updated: August, 0 EB-0-00 Tab Schedule Page 0 of 0 Items # and # represent significant expenditures to connect renewable generators to the Hydro One transmission system. Capital expenditures of almost $ million will be required to connect FIT generators and approximately $ million to connect non- FIT renewable generators. Non-FIT connections include mainly renewable projects arising from other OPA procurement programs and government initiatives (Green Energy Investment Agreement) or directives (e.g. Hydro Electric Energy Supply Agreements). Generation connection work is expected to exceed $ million over the two Test Years; however, the vast majority of this work is to be fully recovered from the generation proponents. Less than $ million of the costs are expected to be recovered from rates. Further details of generation connections are provided in Tables and of Exhibit D, Tab, Schedule, Appendix A and the ISD s #D0, D, D, D, D, D and #D at Exhibit D, Tab, Schedule. 0 Item # and # are included to illustrate the additional benefits provided by other investments in the rate submission to facilitate renewable generation. Upgrades at both Allanburg TS and Hawthorne TS are required to address the high short circuit levels which are at or exceeding equipment capabilities. The upgrades involve mainly replacing existing oil circuit breakers with new higher rated SF breakers. In situations where the short circuit levels are being exceeded, interim operating measures are in place including opening bus-tie breakers. Such measures result in reduced reliability at these stations as the switchyards are now split into smaller subsystems with much less redundancy. The primary driver for the upgrade at these stations is to restore the reliability to previous levels. Further details of these investments are provided in Table 0 of Exhibit D, Tab, Schedule, Appendix A and ISD s #D0 and #D at Exhibit D, Tab, Schedule. A secondary benefit of these upgrades is that it will provide for significantly increased capability to connect additional renewable generation. At present, the limitations at

11 Updated: August, 0 EB-0-00 Tab Schedule Page of Allanburg are constraining additional generation connection in the Niagara Peninsula. Similarly limitations at Hawthorne TS are constraining the generation connections in the greater Ottawa and surrounding areas. The upgrades will allow connection of up to 0MW of additional generation in the Allanburg area and up to 00MW of additional generation in the Ottawa area. Item # represents all of the P&C upgrades required to enable renewable generation connections. This includes: 0 Enhanced transfer trip signalling to allow transmission outages to proceed with reduced impact to distribution connected generation Transmission Station P&C upgrades for distribution connected generation Further details on these investments are provided in Exhibit D, Tab, Schedule, Section. and Table of Appendix A, and ISD s #D and #D at Exhibit D, Tab, Schedule. Item # represents all of the P&C modifications required to address the consequences of the generation already connected to the distribution systems. This includes: 0 Transmission P&C modifications to mitigate the power distance limitation, Modifications to maintain compliance with under-frequency load shedding requirements (UFLS) and to preserve required load rejection capability, Other work including: expansion to the operating infrastructure required to monitor all of the new generation and associated protection systems; and systems to manage generation curtailment during outages.

12 Updated: August, 0 EB-0-00 Tab Schedule Page of Further details on these investments are provided in Exhibit D, Tab, Schedule, Section. and Table of Appendix A, and ISD s #D and #D at Exhibit D, Tab, Schedule.. Licence Amendment to Upgrade TS s to Facilitate Renewable Generation 0 In addition to the projects in Table, Hydro One is performing work to upgrade existing transformer stations to facilitate small scale renewable generation as per the license amendment issued on March, 0. The license amendment required Hydro One to upgrade up to transformer stations subject to the scope and timing recommended by the OPA. On April, 0, the OPA sent a letter (attached in Appendix C to this exhibit) advising Hydro One to upgrade 0 transformer stations. Upgrades were to be performed at the following stations: 0. Kingsville TS. Kent TS. Port Hope TS. Birch TS. Caledonia TS. Clarke TS. Keith TS. Longwood TS. Nebo TS 0. Goderich TS Upon further investigation and engineering review, alternative approaches were identified for Port Hope and Birch which did not require further work to be done to accommodate

13 Updated: August, 0 EB-0-00 Tab Schedule Page of the small scale generation at these stations. Subsequent to the OPA letter, transformer upgrades for increasing load connection capacity at Nebo TS was identified and therefore the originally proposed upgrades to Nebo TS would not be needed. Further details of the work at Nebo can be found in the ISD #D at Exhibit D, Tab, Schedule. 0 Transformer upgrade work was performed at Kent TS and Goderich TS to increase reverse flow transformation capacity. Bus tie reactors were added to the Kingsville, Caledonia, Clarke, Keith, and Longwood transformer stations to increase short circuit capability at these stations. Work at Kingsville TS was completed in 0 and the other six stations will be completed in 0. The total cost for the seven stations is $. million. Hydro One has not recovered these costs from ratepayers as per the licence amendment.. OM&A Costs related to the Green Energy Plan 0 Exhibit C, Tab, Schedule describes the Development OM&A work Hydro One plans to undertake in 0 and 0. The work includes R&D studies and pilot projects, the development of technical standards, and development of the Advanced Distribution System (ADS or Smart Grid). A significant amount of this work is related to accommodating the connection of renewable generation to the transmission and distribution systems in Ontario. As such, these OM&A costs are also part of the Green Energy Plan..0 RECOVERY OF DEVELOPMENT COSTS FOR EARLIER GREEN ENERGY PROJECTS In Exhibits F, Tab, Schedules and, Hydro One is requesting recovery of a deferral account for costs incurred in 00 for OM&A development work on projects included in

14 Updated: August, 0 EB-0-00 Tab Schedule Page of the EB Green Energy Plan. This section provides background information to support why Hydro One should be allowed recovery of these costs. On May, 00, the Board established a deferral account for projects related to the Green Energy Act that had been identified by the OPA in the Integrated Power System Plan (IPSP). On March, 00, the Board expanded the list of projects to include other green projects listed in the Minister of Energy s letter to Hydro One dated September, 00 that were not already included in the deferral account. 0 Hydro One initiated an aggressive program of OM&A development work on certain priority projects following the Minister s letter of September, 00. The letter instructed Hydro One to immediately proceed with the planning, development and implementation of Transmission Projects outlined in the attached Schedule A. The letter required Hydro One s Chairman to return a signed copy stating I concur. Based on this direct instruction and commitment; and based on the target in-service dates listed in Schedule A for some of the projects, work had to ramp up very quickly in order to meet the in-service dates. 0 In November of 00, Hydro One began discussions with Ministry staff about its implementation plan. In accordance with the September, 00 letter from the Minister, on December, 00 Hydro One submitted to the Minister of Energy and Infrastructure, a status report on the Transmission and Distribution Projects in Support of Renewable Energy Projects (attached in Appendix D to this exhibit). As part of the EB Decision, the Board approved the recovery of $. million incurred in 00 in the deferral account. This was the early portion of the development work referred to above. It is important to note that the amount of $. million incurred and recorded in the account in 00 was for continuation of the same type of work as that

15 Updated: August, 0 EB-0-00 Tab Schedule Page of incurred in 00 and for continuing to implement the Plan as submitted to the Minister. These costs were incurred prior to the Board s approval of the Electricity Transmitter Designation process in EB and were in direct response to the Minister s letter and instruction of September, 00. The only way Hydro One could have met the inservice dates established by the Minister in Schedule A of the letter was to proceed immediately and aggressively on the development work. The development work involved a large degree of outsourcing partly to acquire the right expertise and partly to acquire enough resources to meet the very tight time frames set by the aggressive inservice dates. 0 0 As indicated in Section. above, the development work on the Schedule A projects was suspended following the Minister s letter of May, 00 to Hydro One and May, 00 to the Ontario Power Authority (both attached in Appendix B to this exhibit). Although not rescinded, statements made in these letters make it very clear that the September, 00 instructions to Hydro One were in question. Therefore, until clear direction was received, Hydro One suspended all development work on the Schedule A projects. It was, however not appropriate for Hydro One to suspend the development work prior to the issuance of these letters as that would not have complied with the Minister s instruction. Therefore, Hydro One submits that although circumstances were changing, the development work that was charged to the deferral account until May of 00 is entirely valid and in keeping with the Minister s and shareholder s instructions.. Prioritization of Projects Due to the amount of time needed for consultation, approvals and construction of large transmission projects, development work had to begin immediately on the priority Green Energy projects in order to meet their target in-service dates. Hydro One selected those projects where there was an urgency to begin development work primarily based on the

16 Updated: August, 0 EB-0-00 Tab Schedule Page of target in-service date and based on the following criteria: 0 All the Core Transmission lines (bulk transmission upgrades) listed in Schedule A were prioritized given their wide areas of service and relatively long lead times, other than the Bowmanville x GTA 00 kv line which was deferred pending a decision on whether to add new nuclear capacity at Darlington, Of the Enabling Transmission lines in Schedule A, only the Goderich and Manitoulin Island Enablers were prioritized given the potential benefits and the expectation that the need would be relatively near term. Development work on all other projects was to be initiated following the OPA s Economic Connection Test process, The one regional transmission project prioritized was the Northwest Transmission line. This project was determined to be a priority given the Minister s target inservice date of 0 and the various potential benefits including connection of new renewable generation, service to additional gold mining in the area and to new chromite mining in the Ring of Fire. The priority projects are listed in Table.

17 Updated: August, 0 EB-0-00 Tab Schedule Page of. Cost Breakdown Table Amounts incurred Project Name in 00 ($M) Goderich Area Enabler 0. Northwest Transmission Line. Manitoulin Island Enabler Line 0. East-West Tie TX Development 0. North South Transmission Expansion. Hanmer x Mississagi 0. West of London TX Line Development 0. Total. 0 The cost of $. million is divided primarily between internal labour and contract work with smaller amounts for miscellaneous equipment and helicopter surveys to study route options, feasibility and determine environmental and construction issues. Internal labour includes project management and estimation, environmental engineering and design, drafting, and conceptual engineering. Contract work included contracts awarded for detailed environmental, GIS (or mapping) and engineering work. These costs are included in the request for recovery of the deferral account in Exhibit F, Tab, Schedule and Exhibit F, Tab, Schedule.. Recovery of Costs Hydro One submits that the Board should approve the recovery of these development

18 Updated: August, 0 EB-0-00 Tab Schedule Page of 0 costs. Hydro One acted prudently and appropriately in carrying out this development work in 00. In particular, Hydro One notes that the Minister s letter of September, 00 included a request to the company to immediately proceed with the planning, development and implementation of the Transmission Projects outlined in the attached Schedule A. The letter included in-service dates in Schedule A that required a very aggressive pace of development work in order to complete the large number of major projects within the prescribed time frame. Furthermore, the letter required Hydro One s chairman to sign the letter under the statement I concur and return the letter to the Minister. The company had made a very serious commitment to the Minister to deliver on this work.