Source: https://www.scribd.com/document/131305491/Feb-15-PFeb-15-PSC-filing-re-Dunkirk-mothball-pdf
Timestamp: 2016-09-26 06:28:02
Document Index: 18450488

Matched Legal Cases: ['art 2', 'art 2', 'art 2', 'ART 2', 'art 2', 'art 2', 'art 1', 'art 2', 'art 2', 'art 1', 'art 1', 'art 2', 'art 2', 'art 2', 'art 1', 'art 2', 'art 2', 'art 2', 'art 1', 'art 2', 'art 2', 'art 2', 'art 2', 'art 2']

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February 15, 2013 Via Electronic Filing Hon. Jeffrey Cohen, Acting Secretary State of New York Public Service Commission Office of the Secretary Three Empire State Plaza Albany, NY 12223-1350 Re: Case 12-E-0577 – Proceeding on Motion of the Commission to Examine Repowering Alternatives to Utility Transmission Reinforcements – Estimated Cost of Transmission Upgrades
Dear Acting Secretary Cohen: Pursuant to the Commission’s January 18, 2013 Order Instituting Proceeding and Requiring Evaluation of Generation Repowering (“January 18 Order”) in this case, Niagara Mohawk Power Corporation d/b/a National Grid (“National Grid” or the “Company”) hereby submits information relating to estimated costs of anticipated transmission system upgrades to address long-term reliability needs resulting from retirement of the Dunkirk Power LLC generating facility (“Dunkirk”) located in Dunkirk, New York. In the January 18 Order, the Commission noted that the Company was implementing transmission reinforcements to reduce reliance on Reliability Support Services (“RSS”) arrangements for some or all of the generation in the intermediate-term (one - four years), and directed National Grid to submit information on the anticipated costs of transmission reinforcements to address the entire long-term impact of the Dunkirk mothballing that could take four or more years to complete. Id. at 2. The Company has identified the following five transmission reinforcement projects to address the long-term reliability concerns from the shutdown of Dunkirk: • • • Addition of two 33.3 MVAr capacitor banks on the two Dunkirk 115kV bus sections ($2.5 million). Addition of a second 75 MVAr capacitor bank at the Huntley 115kV switchyard ($1.4 million). Reconductoring of the two 115kV lines between Five Mile Road and Homer Hill, each approximately 7.4 miles in length ($18.0 million).
300 Erie Blvd. West, Syracuse, New York 13202 T: 315/428-5862F: 315/ 428-5355carlos.gavilondo@nationalgrid.com   www.nationalgrid.com
Acting Secretary Cohen February 15, 2013 Page 2 of 3
Reconductoring of one mile of the Niagara – Gardenville #180 line ($4.0 million). Reconductoring of 14 miles of the Packard – Erie #181 line ($37.1 million).
Implementing the foregoing projects is expected to address all N-1 problems and greatly mitigate N-1-1 exposure resulting from the shutdown of Dunkirk through at least 2021. The first three projects (Dunkirk and Huntley capacitor banks and reconductoring between Five Mile Road and Homer Hill) are included in the Company’s current capital investment plan, and are planned to be in service within three years. The total costs of these three projects ($21.9 million) reflect conceptual grade engineering estimates (-25% to +50%). Implementation of these three projects is necessary to enable the Company to eliminate reliance on RSS arrangements. The last two projects (reconductoring on the #180 and #181 lines) are not in the Company’s current capital plan; however, the Company estimates these projects could be placed into service no later than 2018 - 2019. The total costs of these two projects ($41.1 million) reflect investment grade engineering estimates (-50% to +200%). These two projects are intended to address additional, less severe thermal overload conditions resulting from the Dunkirk shutdown. Using operational measures to address the issues in the short term can be accepted on a temporary basis, but the issues must be mitigated in the long-term. These two projects are anticipated to be included in the analysis comparing the required transmission upgrades and the Dunkirk repowering proposal. Detailed information regarding the need for the five projects is set forth in the September 26, 2012 study titled “Review of Dunkirk Mothball Notice – Part 2; Review of Additional Solutions Associated with Dunkirk Mothball Notice” (“Dunkirk Part 2 Study”). A redacted copy of the Dunkirk Part 2 Study is included as Attachment 1 to this letter, and a confidential version will be filed with the Records Access Officer. To the extent there are other significant changes affecting the transmission system beyond those studied in 2012, additional reinforcements may be needed. In the January 18 Order, the Commission also directed National Grid to solicit information from Dunkirk about the costs and benefits of repowering that facility, and to evaluate the repowering against proposed long-term transmission alternatives to address the long-term reliability concerns and provide a report and recommendation to the Commission based on that evaluation. The Company expects to issue an RFP to Dunkirk by February 19 requesting information on the potential repowering of that facility. The Company anticipates receiving information from Dunkirk by March 19, 2013. The Company will evaluate the information received from Dunkirk to compare the repowering alternative with the identified transmission upgrades and will submit a report and recommendation to the Commission based on its analysis by April 18, 2013.
Acting Secretary Cohen February 15, 2013 Page 3 of 3
Please contact me if you have any questions. Thank you for your attention to this matter. Respectfully submitted,
/s/ Carlos A. Gavilondo Carlos A. Gavilondo
Denise Gerbsch Tammy Mitchell Case 12-E-0577 Active Parties List (via DMM)
REVIEW OF DUNKIRK MOTHBALL NOTICE PART 2 STUDY (Redacted) (Sept. 26, 2012)
REVIEW OF DUNKIRK MOTHBALL NOTICE – Part 2 REVIEW OF ADDITIONAL SOLUTIONS ASSOCIATED WITH DUNKIRK MOTHBALL NOTICE Version 0 September 26, 2012
Principal Contributor: Jeffery Maher, PE National Grid 300 Erie Blvd West Syracuse, New York 13202
This document and all attachments hereto (the "Document") is being provided to you by, or on behalf of, a National Grid USA affiliated company (the “Company”), but only upon and subject to the express understanding that: (a) neither the Company, its parents or affiliates, nor any of their respective officers, directors, agents, or employees, make any warranty, assurance, guaranty, or representation with respect to the contents of the Document or the accuracy or completeness of the information contained or referenced in the Document, (b) the Company, its parents and affiliates, and their respective officers, directors, agents, and employees, shall have no liability or responsibility for inaccuracies, errors, or omissions in, or any technical, business, policy, or other decisions made by any direct or indirect recipient in reliance on, the Document or the information contained or referenced therein; all such liability is expressly disclaimed, (c) recipient(s) of the Document shall not acquire any rights in or to the Document, or to the information contained or referenced therein, by virtue of its disclosure, (d) no license to any such recipients, under any trademark, patent, or other intellectual property right, is either granted or implied by the provision of the Document to the recipient(s), and (e) the provision of the Document and/or the contents thereof shall not be deemed to be an inducement or a commitment by the Company, its parents or affiliates, or any of their respective officers, directors, agents, or employees, to enter into or proceed with any transaction. If the Document is specified as being a deliverable to the recipient under any written agreement currently in effect between the Company and recipient (an “Agreement”), then, in the event of any conflict between the preceding paragraph and the express terms of the Agreement, the express conflicting term(s) of the Agreement shall govern to resolve such conflict.
Review of Dunkirk Mothball Notice – Part 2
Table of Contents 1. Executive Summary ............................................................................................ 2. Introduction ......................................................................................................... 3. Study Details........................................................................................................ 3.1. Discussion of Case Levels ......................................................................... 3.2. System Generation ..................................................................................... 3.3. Gardenville 230/115kV Transformers ........................................................ 3.4. Dunkirk 230/115kV Transformers .............................................................. 3.5. Five Mile Rd 345/115kV Transformer ......................................................... 4. Study Methodology ............................................................................................. 5. System Response for Outage of all Dunkirk Generation .................................. 5.1. N-1 System Conditions............................................................................... 5.2. N-1-1 System Conditions............................................................................ 5.3. Sensitivity to Interim Conditions ............................................................... 5.4. Niagara – Packard Overloads .................................................................... 6. Solutions to Additional First Level (A1) Needs ................................................. 6.1. Dunkirk Area Low Voltages........................................................................ 6.2. Packard – Erie and Niagara – Gardenville Overloads .............................. 6.3. N-1 and N-1-1 System Results for First Level Plan (A1) ........................... 7. Solutions to Additional Second Level (A2) Needs ............................................ 7.1. Dunkirk Area Low Voltages and Frontier Overloads ................................ 7.2. Homer Hill Area Overloads......................................................................... 7.3. N-1 and N-1-1 System Results for Second Level Plan (A2) ...................... 8. Solutions to Additional Fifth Level (A5) Needs ................................................. 8.1. Second Level Solution to Fifth Level Needs (A5-1) .................................. 8.2. New 230kV Line Solution (A5-2)................................................................. 8.3. Addition of Transformation at Stolle Rd (A5-3) ........................................ 8.4. Addition of a Dysinger – Stolle 345kV Line (A5-4) .................................... 9. Non-Wires Alternatives ....................................................................................... 9.1. Low Voltage Concerns ............................................................................... 9.2. Overloads on Five Mile – Homer Hill Circuits ........................................... 9.3. Overloads on Lines #181 and #180............................................................ 10. Summery ..............................................................................................................
List of Tables Table 1: Summary of Plans Developed Table 2: Study Base Case Conditions Table 3: Summary of N-1 Voltage Needs Identified with Dunkirk Out of Service Table 4: Summary of N-1 Thermal Needs Identified with Dunkirk Out of Service Table 5: Summary of N-1-1 Voltage Needs Identified with Dunkirk Out of Service Table 6: Summary of N-1-1 Thermal Needs Identified with Dunkirk Out of Service Table 7: Summary of N-1 Thermal Needs Identified with Dunkirk Unit 1 In Service Table 8: Summary of Voltage Needs Identified In First Level Cases Table 9: Summary of Thermal Needs Identified In First Level Cases Table 10: Summary of Remaining N-1 Voltage Needs Identified Following Plan A1 Table 11: Summary of Remaining N-1 Thermal Needs Identified Following Plan A1 Table 12: Summary of Remaining N-1-1 Voltage Needs Identified Following Plan A1 Table 13: Summary of Remaining N-1-1 Thermal Needs Identified Following Plan A1 Table 14: Summary of Voltage Needs Identified in Second Level Cases Table 15: Summary of Thermal Needs Identified in Second Level Cases Table 16: Summary of Remaining N-1 Voltage Needs Identified Following Plan A2 Table 17: Summary of Remaining N-1 Thermal Needs Identified Following Plan A2 Table 18: Summary of Remaining N-1-1 Voltage Needs Identified Following Plan A2 Table 19: Summary of Remaining N-1-1 Thermal Needs Identified Following Plan A2 Table 20: Summary of Voltage Needs Identified in First and Second Level Cases Table 21: Summary of Thermal Needs Identified in First and Second Level Cases Table 22: Summary of N-1-1 Voltage Needs Identified in First and Second Level Cases Table 23: Summary of N-1-1 Thermal Needs Identified in First and Second Level Cases Table 24: Summary of Remaining N-1 Voltage Needs Identified Following Solution A5-1 Table 25: Summary of Remaining N-1 Thermal Needs Identified Following Solution A5-1 Table 26: Summary of Remaining N-1-1 Voltage Needs Identified Following Solution A5-1 Table 27: Summary of Remaining N-1-1 Thermal Needs Identified Following Solution A5-1 Table 28: Summary of Remaining N-1 Voltage Needs Identified Following Solution A5-2 Table 29: Summary of Remaining N-1 Thermal Needs Identified Following Solution A5-2 Table 30: Summary of Remaining N-1-1 Voltage Needs Identified Following Solution A5-2 Table 31: Summary of Remaining N-1-1 Thermal Needs Identified Following Solution A5-2 Table 32: Remaining Concerns for Indicated Contingency Table 33: Summary of Remaining N-1 Voltage Needs Identified Following Solution A5-4 Table 34: Summary of Remaining N-1 Thermal Needs Identified Following Solution A5-4 Table 35: Summary of Remaining N-1-1 Voltage Needs Identified Following Solution A5-4 Table 36: Summary of Remaining N-1-1 Thermal Needs Identified Following Solution A5-4 Change Control
Version 0 Date 9/26/12 Modification Initial Document Author(s) J. Maher Reviews and Approvals by J. Hipius & C. Sedewitz
1. Executive Summary This study is the second part of the assessment of the impact of the shutdown of coal fired generation at the Dunkirk facility. It reviews the recommended system upgrades necessary to completely mitigate the impact. Notice was received on March 14, 2012 that NRG plans to place the units in protective layup (mothball) for an unknown amount of time. Before NRG;s announcement, National Grid performed a study of Western NY in 2011; the study reviewed the weaknesses of the existing system and made recommendations to address these needs. The 2011 study determined that severe post-contingency low voltages exist today and will get worse though time. The 2011 study was done with all generation at Dunkirk in service. The 2011 Western Division Solution Study, which had assumed all Dunkirk generation was in-service, recommended system upgrades to address concerns in western NY including a new 345/115kV substation near Homer Hill, reconductoring of line #171, a second Homer Hill capacitor bank and a second bus tie at Dunkirk. After the NRG announcement, National Grid immediately began its analysis of the impact of the plant mothball or shutdown. This analysis was document in two parts to aid in the decision making process. The analysis documented in the first part of this study showed that the shutdown of the generation at Dunkirk would have an immediate negative impact on the system. It was originally found that three Dunkirk units would need to be in service to support the area in the summer and that two would be required in the winter. The Part I Study then concluded that several projects could be completed prior to June 2013 that would reduce the dependency to one Dunkirk 115kV connected generator. The projects, referred to as the interim solutions, included addition of 230kV breakers at Huntley and Packard, installation of National Grid’s mobile capacitor banks at Dunkirk and moving three distribution stations served from Gardenville – Dunkirk lines #141 and #142 to other circuits. The interim solutions and running generation did not fix all area issues, merely restored the system to a state similar to the existing system with all four Dunkirk units running in year 2013. Thus, these interim projects do not eliminate the need to complete the upgrades recommended in the 2011 area study. This second part of the assessment of the impact the Dunkirk shutdown will have on the system looks at the area following all upgrades recommended in Part 1 Study and the 2011 Western NY Area Study. These previously identified projects were included in the base cases, as the 2011 area study determined that they are the most effective options to address the existing area problems. The short duration projects recommended in the first part of this study were also included in study base cases, as it is expected that they will be complete by spring 2013. No mobile capacitor banks at Dunkirk were included in study base cases to determine if there is a continued need for reactive support. This analysis found that the shutdown results in low voltages for several contingencies in the Dunkirk and Falconer areas and overloads in three locations. One overload was between Five Mile Rd and Homer Hill (both lines) and the other two were between the Niagara/Packard area and the Gardenville/Erie The method of identifying recommended reinforcements was broken into three levels, similar to the 2011 study of the area. However, the level names are not the same as was used in the previous 2011 study as these were found to be overly complicated. The first level plan (called plan A1) was to address the N-1 low voltages and overloads with Indeck Olean in service. The second level plan (called plan A2) was to address the N-1 low voltages and overloads with Indeck Olean out of service. The fifth level plan (called A5) was to address the N-1-1 low voltages and overloads with Indeck Olean out of service. All of these levels Review of Dunkirk Mothball Notice – Part 2 4
assumed that Jamestown was at a 75-80 MW load level. Plans were not developed solely for the third, fourth or sixth levels. Though plans were developed for the fourth and sixth levels in the 2011 area study, they were not the recommended solutions. As will be seen, the first level recommendations addressed all of the concerns in the third level cases. Through the course of the study, it was determined that though the first level plan (A1) addressed all N-1 events, it left the system exposed to N-1-1 overloads that surpassed the STE rating. The case started with all generation at Indeck Olean and Jamestown in service,
following adoption of the expected BES definition and the revised TPL standards. Therefore, while a plan for this level is discussed in this report, it is not the recommended solution. It was also found that the difference between the second level (A2) recommendation and the fifth level recommendation (A5) would be minimal and thus it is recommended to eliminate the exposure to the N-1-1 low voltages by proceeding with the fifth level plan (A5). The recommendation to proceed with this plan (A5) will leave the system in a state similar to the state it would have been in after completion of the projects recommended in the 2011 area study, had Dunkirk not shutdown. The projects recommended to address the needs discussed within this report are: • • • Addition of two 33.3 MVAr capacitor banks on the two Dunkirk 115kV bus sections. This project should be implemented as soon as possible. ($2.5M) Addition of a second 75 MVAr capacitor bank at the Huntley 115kV switchyard. This project should be implemented as soon as possible. ($1.4M) Reconductoring of the two 115kV lines between Five Mile Rd and Homer Hill, each approximately 7.4 miles in length. This project is recommended to be executed such that it is complete when Five Mile Rd comes into service. If the project cannot be completed by the time Five Mile Rd is completed, a review of the risk associated with the outage/overload and the cost of continued operation of generation at Dunkirk will have to be undertaken to determine when the shutdown of the generation can occur. ($17M$19M) Reconductoring of one mile of the Niagara – Gardenville #180 line. To facilitate the retirement of the generation as soon as possible, this project is recommended to be implemented such that it is complete at or before Five Mile Rd coming into service. If the project cannot be completed by the time Five Mile Rd is completed, a review of the risk associated with the outage/overload and the cost of continued operation of generation will have to be undertaken to determine when the shutdown of the generation can occur. ($3.7M) Reconductoring of 14 miles of the Packard – Erie #181 line. To facilitate the retirement of the generation as soon as possible, this project is recommended to be implemented such that it is complete at or before Five Mile Rd coming into service. If the project cannot be completed by the time Five Mile Rd is completed, a review of the risk associated with the outage/overload and the cost of continued operation of generation at Dunkirk will have to be undertaken to determine when the shutdown of the generation can occur. ($35M-$40M)
The expected cost of this set of projects is in the range of $60M-$67M based on investment grade estimates with a range of -50% - +200%. Following the addition of these projects to the study base cases, no N-1 thermal or voltage problems will be present. N-1-1 testing was then performed. This testing determined that Review of Dunkirk Mothball Notice – Part 2 5
while N-1-1 problems do exist, they are for combinations of single element outages followed by a multiple element outage; tested per the NPCC requirements. These overloads or low voltages were on non-BPS elements and thus correction of these issues is not mandatory. Further review of these issues will be done in the next area study to confirm that there will be sufficient time for operators to take corrective actions following the second event. Some minor N-1-1 problems were also found in cases with all generation at the City of Jamestown and Indeck Olean out of service. This is considered a sixth level case, and the low voltages or overloads are not recommended for correction.
2. Introduction This study examines the impact of the announced closure of the generation at the Dunkirk facility in western NY. It summarizes the third and fourth phases of this study, which is a determination of what projects would be necessary to address all required N-1 and N-1-1 conditions with all Dunkirk generation out of service. The first two phases were documented in part 1 of this study. 3. Study Details This review was done using the summer and winter 2016 and 2021 cases that were used in the 2011 needs assessment of the area. Information on these cases, including load levels, forecasts and generation dispatch can be found in sections 4 and 5 of the 2011 Needs Assessment report. It is believed that the load magnitude and distribution across the system used in the 2011 study is representative of the peak loads that would be expected for the summer of 2013. The starting point of this assessment was the system with the recommended reinforcements, as shown in the executive summary of the 2011 Western NY Solution Report in service. These upgrades include: • Construction of a new 345/115kV station north of Homer Hill station connecting to the Homer City – Stolle 345kV line #37 and the Gardenville – Homer Hill #151 and #167 circuits. This station, referred to as Five Mile Rd, includes a single 345/115 standard size 448 MVA transformer and a single 25 MVAr capacitor bank Installation of a second 33.3 MVAr capacitor bank at Homer Hill station and reinstallation of the previously removed capacitor cans to increase the size of the existing capacitor bank from 27 MVAr to its designed size of 32 MVAr Reconductoring the Warren – Falconer #171 line Closure of the Normally Open switch at Andover station and reinstallation of the previously removed capacitor cans to increase the size of the Andover capacitor bank from 10 MVAr back to its designed size of 15 MVAr Installation of a second breaker in series with the existing Dunkirk 115kV bus tie breaker
The 2011 needs study also noted that the following projects are being implemented for capacity or condition reasons and were thus included in the study base cases: • • • Addition of a single 75 MVAr capacitor bank at Huntley Reconductoring on 0.3 miles of Gardenville – Erie #54 A complete rebuild of the Gardenville 115kV station including replacement of TB #3 and #4 with larger units and installation of four 75 MVAr capacitor banks
In addition to these system upgrades, the following system changes or upgrades were recommended in the July 27, 2012 report titled “Review of Dunkirk Mothball Notice-Part 1” and are associated with the shutdown of the Dunkirk generation. Note that the installation of the mobile capacitor banks at any station is not included in the base cases to determine if the need exists for permanent reinforcements. Addition of a 230kV breaker at Huntley, which creates a new bus section. Bus section 68 (left side of station) will be lines #78, #79 and generator 68. The middle bus section Review of Dunkirk Mothball Notice – Part 2 7 •
will be cable #70. Bus section 67 (right side of station) will be lines #77, #80 and generator 67. • Addition of a 230kV breaker at Packard, which creates a new bus section. Bus section 4 (left side of station) will be lines #62, #77 and TB #4. Bus section 3 (the middle bus section) will be line #76. Bus section 2 (right side of station) will be lines #61, #78 and TB#2. Moving three distribution stations served from Gardenville – Dunkirk #141 and #142 to other circuits. The three changes are moving Bennett Rd station from line #142 to line #161, moving Station #139 from circuits #141 and #142 to circuits #149 and #150 and moving Station 55 from circuits #141 and #142 to circuits #145 and #146
3.1. Discussion of Case Levels As a reminder, the 2011 Solution Study for the area broke the analysis into six levels to help quantify risk. These same levels are used within this study and are shown in the table below. To clarify the discussion, the second level plus was renamed to the fifth level and the fourth level plus was renamed to the sixth level. To simplify the analysis, plans were only developed for three conditions (not all six). Plans were developed for the first, second and fifth levels, but not the third, fourth and sixth levels. One plan will be developed to address the First level needs, which essentially corrects all concerns that exist for N-1 conditions with Indeck Olean in service. Within this report, this plan will be referred to as the A1 plan. The second plan to be developed will address all Second level needs. Within this report, this plan will be referred to as the A2 plan. A third plan will be developed to address all fifth level needs. Within this report, this plan will be referred to as the A5 plan. A third, fourth and sixth level plan will not be developed at this time. This is consistent with the recommendation of the 2011 area study. These levels were the cases with Jamestown’s load at ~100 MW. As will be seen, the plans developed happen to address most of the concerns with Jamestown at ~100 MW. This was not by design, but rather due to the lumpiness of transmission solutions. The analysis of the recommended plans will demonstrate what risks will remain following the completion of the upgrades. The 2012 study of the region will further review potential solutions to the fourth and sixth level if necessary. Case Level Level 1 Level 2 Level 3 Level 4 Indeck Olean In Out In Out Line 171 In In In In Table 1: Summary of Plans Developed Jamestown All Lines Single Element Multiple Element Net Load in Service Outage (N-1) Outage (N-1) ~75-80 MW First Level First Level First Level ~75-80 MW First Level First Level Second Level ~100-105 MW First Level Third Level Third Level ~100-105 MW Fourth Level Fourth Level Fourth Level Multiple Element Outage (N-1-1) Fifth Level Fifth Level Sixth Level Sixth Level
3.2. System Generation Four system base case conditions were reviewed as shown in the table below. All analysis assumes that the 230kV connected generation at Huntley, the 115kV Review of Dunkirk Mothball Notice – Part 2 8
connected generation at Indeck Yerkes and the 115kV connected generation at Oxbow power (both connected to the system near Huntley) were in service. This is consistent with what was done in the 2011 Western Division Solution Study. All wind generation at Arcade and Steel winds was modeled as out of service due to wind generations uncertain nature, especially as its typical output during system peak conditions is very low. Huntley Units 67 and 68 In Service In Service In Service In Service Indeck Yerkes In Service In Service In Service In Service Table 2: Study Base Case Conditions Oxbow Indeck Line Power Olean 171 In Service In Service Reconductored In Service In Service Reconductored In Service Out of Service Reconductored In Service Out of Service Reconductored Jamestown Net Load ~75-80 MW ~100-105 MW ~75-80 MW ~100-105 MW
3.3. Gardenville 230/115kV Transformers System Operators frequently adjust the LTC settings of the National Grid and NYSEG 230/115kV transformers at Gardenville. For nearly all hours between June 2003 and September 2010, the 115kV voltage at Gardenville was above 102% of nominal. The voltages were at 103%-105% of nominal about 96% of the time. In all study base cases, the transformers were adjusted to hold the 115kV voltage to about 104.5%. The LTC setting was also chosen so that voltages at all major buses in the system were kept below 105%. This did not result in any 230kV pre-contingency voltages being outside acceptable limits. 3.4. Dunkirk 230/115kV Transformers Historically, System Operators have almost never adjusted the LTC settings of the 230/115kV transformers at Dunkirk. Typically, the generation is used to manage the 115kV and 230kV voltages. Loss of these machines will require that LTC adjustment begin being used. For each season, year and dispatch, the voltages in the area were reviewed and a setting chosen to hold the Dunkirk 115kV voltage up around 104%. Today, per the Power Control Procedures, operators actually hold the voltage higher, up to 107%, but 104% was used to maintain some system margin. The LTC setting was also chosen so that voltages at all other major buses in the system were kept below 105%. 3.5. Five Mile Rd 345/115kV Transformer For each season, year and dispatch, the voltages in the area were reviewed and a LTC setting chosen to hold the Five Mile Rd 115kV voltage up around 104%. The LTC setting was also chosen so that voltages at all major buses in the system were kept below 105%. Prior to beginning this review, impedance calculations were reviewed and updated based on the planned location for the new station. This has resulted in some changes from the analysis shown in the 2011 area study report. Review of Dunkirk Mothball Notice – Part 2 9
4. Study Methodology The study methodology is similar to that used in the 2011 area Needs Assessment and Solution Study and is documented in sections 3, 4, 5 and 6 of the 2011 Western Division Area Review Part 1 – Needs Assessment Study. These descriptions are not repeated here. In addition to this methodology, when running N-1-1 analysis, the operator emergency low limits and load shed limits, as discussed in the first part of this study, were used. 5. System Response for Outage of all Dunkirk Generation 5.1. N-1 System Conditions The following tables show the results of N-1 testing for the system with all Dunkirk units out of service and the planned area upgrades completed. All tables within this report use a short description to indicate the contingency being presented. Space constraints prevent fully describing the contingency. A full description for each outage can be found in Appendix C of the 2011 Needs Assessment. All contingencies listed in Appendix C were tested as part of this assessment.
Indeck Olean In Service In Service In Service In Service Out of Service Out of Service Out of Service Out of Service In Service In Service In Service In Service In Service In Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service
Line 171 Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored
Table 3: Summary of N-1 Voltage Needs Identified with Dunkirk Out of Service Jamestown Winter Winter Outage Element Net Load Peak 2016 Peak 2021 ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW
Summer Peak 2021
Table 4: Summary of N-1 Thermal Needs Identified with Dunkirk Out of Service Indeck Line Jamestown Winter Winter Outage Element Olean 171 Net Load Peak 2016 Peak 2021 In Service Reconductored ~75-80 MW In Service Reconductored ~75-80 MW In Service Reconductored ~75-80 MW In Service Reconductored ~75-80 MW In Service Reconductored ~75-80 MW In Service Reconductored ~75-80 MW In Service Reconductored ~75-80 MW In Service Reconductored ~75-80 MW Out of Service Reconductored ~75-80 MW Review of Dunkirk Mothball Notice – Part 2
Summer Peak 2021 -
Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service In Service In Service In Service In Service In Service In Service In Service In Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service
Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored
~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW 12
5.2. N-1-1 System Conditions In addition to the N-1 needs identified, several N-1-1 conditions were reviewed. N-1-1 analysis can be very burdensome to run and review. To reduce the time to run the analysis and to limit the results that needed to be reviewed and presented here, the full N-1-1 analysis was initially only run on two cases, a summer 2021 and a winter 2021 case. Both initial cases assumed that Indeck Olean was out of service and that the Jamestown load was approximately 100 MW. This analysis identified the contingencies that resulted in system problems. A reduced number of N-1-1 combinations were then run on all other cases. When presenting results, only voltages that were below the operators load shed limit (see discussion in the first part of the Dunkirk Mothball Study) and overloads that surpassed the element’s STE rating are shown. No overloads that are on facilities shown in the tables above in section 5.1 for N-1 conditions are repeated in this section
From the N-1 analysis for the second level cases, it can also be observed that if the case had assumed Indeck Olean was in service It is expected that correction of the overload on these lines will be mandatory when considering the expected definition of BES and the proposed revisions to the TPL standards (TPL-001-2). Finally only applicable N-1-1 combinations and impacts are described here. As discussed in the 2011 Western NY Needs and Solutions studies, the applicable contingencies are as follows: 1. Loss of any single transmission circuit, transformer, generator or DC line operated at any voltage, followed by any other single transmission circuit, transformer, generator or DC line operated at any voltage. The system response at all 100kV and above elements is considered. 2. Loss of any BPS element, followed by any design contingency at any voltage. The system response on all BPS elements is considered. The impact of this combination on non-BPS elements is not addressed in this study and typically not considered. However, if system impacts are considered severe then a business case to review and address them would be performed on a case by case basis. 3. Loss of any long lead time item operated at any voltage, followed by any design contingency at any voltage. Long lead time items include generators, equipment at gas insulated substations, underground cables, and large power transformers. The system response at all 100kV and above elements is considered. As can be inferred by #1 and #2 above, correction of the impact of a single element outage, followed by a multiple element outage on a non-BPS facility is not mandatory and is not discussed in the following tables. Note that the Dunkirk 230kV bus is not BPS.
Indeck Olean In Service In Service In Service In Service In Service In Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service In Service In Service In Service In Service In Service In Service In Service In Service In Service In Service In Service In Service In Service Out of Service Out of Service Out of Service Out of Service Out of Service
Line 171 Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored
Table 5: Summary of N-1-1 Voltage Needs Identified with Dunkirk Out of Service Jamestown First Second Winter Winter Element Net Load Outage Outage Peak 2016 Peak 2021 ~100-105 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW
Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service
Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored
~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW Table 6: Summary of N-1-1 Thermal Needs Identified with Dunkirk Out of Service Jamestown First Second Winter Winter Element Net Load Outage Outage Peak 2016 Peak 2021 ~75-80 MW ~100-105 MW ~100-105 MW ~100-105 MW Summer Peak 2016 Summer Peak 2021 -
Indeck Olean Out of Service Out of Service Out of Service Out of Service
Line 171 Reconductored Reconductored Reconductored Reconductored
5.3. Sensitivity to Interim Conditions To assess the need for continued operation of the Dunkirk generation and to provide some insight to the risk associated with the low voltages and overloads identified, two sensitivity cases were tested. These cases included the two 52.5 MVAr mobile capacitor banks installed at Dunkirk and Dunkirk 115kV unit #1 in service. The sensitivity testing only reviewed the summer 2016 peak load cases. One case had Indeck Olean in service, the other had Indeck Olean out of service. Both cases tested had one Jamestown generator in service, for a net load of about 80 MW. It was found that there were no N-1 voltages outside of planning criteria. The table below shows all N-1 thermal overloads found. No voltages were below the load shed limit for any applicable N-1-1 contingency and none of the tested N-1-1 outages resulted in loading over STE on the applicable facilities. N-1-1 testing with Dunkirk Unit #1 as the first contingency was not competed. Only a desktop review of the winter performance was completed. It is expected that there would be no unacceptable N-1 or N-1-1 thermal overloads or low voltages in the same winter cases. Additional testing would be necessary to confirm this. Indeck Olean In Service In Service In Service In Service In Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Table 7: Summary of N-1 Thermal Needs Identified with Dunkirk Unit 1 In Service Line Jamestown Outage Element 171 Net Load Reconductored ~75-80 MW Reconductored ~75-80 MW Reconductored ~75-80 MW Reconductored ~75-80 MW Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW Summer Peak 2016
5.4. Niagara – Packard Overloads
These overloads are not discussed in this report. This is because a NYSRC operating exception exists that allows these lines to be operated Review of Dunkirk Mothball Notice – Part 2 16
up to their STE rating as generation adjustment can occur very quickly that will correct the overloads. As described in the 2011 Western NY Needs Assessment, N-1-1 overloads in the Niagara/Packard area can all be mitigated These concerns are not discussed here. Some contingencies did not result in National Grid equipment surpassing its LTE rating. No National Grid equipment surpassed its STE rating.
6. Solutions to Additional First Level (A1) Needs As a reminder, the following tables show the additional N-1 low voltages and overloads that were determined to be first level (A1) needs. Notice that the thermal overloads only develop in the summer and that the voltage problems tended to be worse in the summer.
Indeck Olean In Service In Service In Service In Service Indeck Olean In Service In Service In Service In Service In Service In Service In Service In Service
Table 8: Summary of Voltage Needs Identified In First Level Cases Jamestown Winter Winter Outage Element Net Load Peak 2016 Peak 2021 ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW
Line 171 Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored
Table 9: Summary of Thermal Needs Identified In First Level Cases Jamestown Winter Winter Outage Element Net Load Peak 2016 Peak 2021 ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW
6.1. Dunkirk Area Low Voltages
The simplest solution to correct these issues is to add a capacitor bank to the 115kV bus at Dunkirk. Area power factor correction was reviewed and it was determined that it would not fully address the low 230kV voltages. The recommended capacitor bank size is 33.3 MVAr, the same as the unit planned for Homer Hill. It was found that using a 54 MVAr unit, the same size as the bank recently installed at Clay, would be oversized for this location; up to 45 MVAr could be installed. Based on a review of other levels, including N-1-1 conditions, the recommended location for the capacitor is on bus section 1. However, either bus section would be acceptable. This may suggest that the ideal configuration would be the installation of two capacitor banks; this will be discussed later in the report. This project may help mitigate the need to run generation at Dunkirk while the other permanent solutions are put into place. For this reason, this project should be completed as soon as possible. Following addition of this project, all 230kV voltages were above 95%. The expected cost of this project is $1.3M and is expected to take 1-2 years to implement. 6.2. Packard – Erie and Niagara – Gardenville Overloads The loss of generation resulted in two overloads in the Frontier region.
The overloads were found in all four levels and for both summer 2016 and 2021. The magnitude of the overload was found to decline in future years, likely due to dispatch and transfer level changes between 2016 and 2021. This suggests that the overload could be more or less severe for other dispatches then the one reviewed in this study. For N-1 conditions, none of the overloads surpassed the STE rating of either line.
Screening of several options, such as reconnecting load taps to other lines, installation of reactors, power factor correction and changing line terminals at each end of the line did not result in any acceptable alternatives, beyond reconductoring the lines or using retired in place circuits as discussed below. Many of these options would reduce the loading on line #181 but increase it on other lines like #180, #182 or even some of the lines connecting to Huntley. As these lines can be heavily loaded during contingency conditions, these increases would not eliminate the need to reconductor circuits, just change which circuits would require the reconductoring.
With Dunkirk in service, the reduced flow into Stolle from Homer City is made up by Review of Dunkirk Mothball Notice – Part 2 19
subsequent flow increases on the lines from the north (#180, #181, #182). However, the line loading increase is not enough to cause overloads during contingency conditions. With the shutdown of Dunkirk, more power will be flowing across the system from the sources in the north to the loads in the south. In addition, more power will be supplied to the Southwest area from Five Mile.
The preferred timing for the reconductoring the #181 line is therefore tied to both the full shutdown of Dunkirk generation and the installation of Five Mile Road substation. Therefore, reconductoring is recommended to be completed concurrently with the completion of Five Mile Rd. The overload s related to increased north to south flow associated with the generation shutdown. To facilitate the retirement of the generation as soon as possible, this project will need to be executed as soon as possible. However, since it was not apparent in the 2013 case in the Dunkirk Mothball Part 1 study, it is recommended that the reconductoring be done by June 2015, consistent with the target date for other major system reinforcements in the area. 6.2.1. Niagara – Gardenville Overloads The overload on line #180 was found to be on a one mile section of 350 copper conductor located just south of the Ellicott junction. Replacement of this conductor will reduce the loading rating, addressing the immediate overload concerns on this line. Additional work may be required in the future to reduce the loading further. The next most limiting element is over 11 miles of 400 copper conductor. Other system changes, including the project to address the #181 overload may help mitigate this overload further The recommended size of the replacement wire is at least 636 ACSR, but to insure adequate future capacity and to align with the National Grid standard sizes, 795 ACSR is preferred. An alternative to this could be utilizing the retired in place 69kV circuit #92. This line shares double circuit towers with the #182 circuit and is 400 Copper (up from the 350 Copper on line #180) in this section. Lines #180 and #182 are on the same double circuit towers from the Packard area until the lines cross Grand Island. At this point, they separate onto different double circuit towers, each sharing a tower with a retired in place 69kV line. It would be possible to keep the lines on the same towers from the Grand Island crossing, all the way to the point in the right of way that line #181 turns and heads toward Erie Station. There is no 350 Copper conductor used on this path. Utilizing this alternate path would correct all loadings Due to the expected concerns with utilizing retired in place assets that are believed to be past their useful life, and the fact that this would only reduce the loading this option is not recommended. This leaves only the reconductoring option to be a viable alternative. The expected cost of reconductoring is $3.7M and is expected to take 3-5 years to implement. Review of Dunkirk Mothball Notice – Part 2 20
6.2.2. Packard – Erie Overloads The overload on line #181 was found to be on a 14 mile section of 350 copper and 636 aluminum conductor located between Packard and Station 130, which is just south of the Ellicott junction. Replacement of this conductor will address the overloads. The recommended size of the replacement wire is at least 795 ACSR. An alternative to this could be utilizing the retired in place 69kV circuit #105. The #181 and #105 circuits share double circuit towers from Packard until Ellicott Junction. Bussing these two lines together would correct most of the overloads. Some reconductoring would be required on the 1.1 mile section between Ellicott junction and Station #130. Reconductoring leaves the circuits impedance relatively unchanged. However, bussing the lines greatly reduces the impedance of the circuit (cuts it in half). Because the impedance is cut in half, the loading on the line increases, to the point that it would trigger the need to do additional reconductoring of a 1.2 mile section between Station #130 and the ECWA Ball Pumping station. At this station, the loading reduces to a point that further reconductoring would not immediately be required. However, additional work on the 1.2 mile section between the pump station and Youngmann station might be needed in the future. Due to the expected concerns with utilizing retired in place assets that are believed to be past their useful life, the bussing option is not recommended. This leaves only the reconductoring option to be a viable alternative. The expected cost of reconductoring is $35M-$40M and is expected to take 5-7 years to implement. 6.2.3. Packard – Erie and Niagara – Gardenville Overloads In an attempt to address both of the overloads between Packard and Erie and between Niagara and Gardenville, an option to utilize the retired in place elements discussed above to create a new line from Packard to Gardenville was reviewed. This option merely energizes the retired in place wire, while doing minimal replacement of structures or conductor. This option would require a new breaker position at Packard and Gardenville. It was found that while it addressed the #181 line overloads and one of the two #180 line overloads
As discussed, there are concerns with using retired in place assets that are believed to be past their useful life. Because of the remaining overload, the concern with the condition of the existing equipment and the need to add new terminal equipment, this option is not recommended.
6.3. N-1 and N-1-1 System Results for First Level Plan (A1) The tables below summarize the N-1 and N-1-1 issues that remain following completion of the recommended projects. The recommended projects to address the First Level, N-1, needs include: • • • Addition of 33.3 MVAr capacitor bank on the Dunkirk 115kV bus. ($1.3M) Reconductoring of one mile of the Niagara – Gardenville #180 line. ($3.7M) Reconductoring of 14 miles of the Packard – Erie #181 line. ($35M-$40M)
Note that many of the N-1 issues in the third and fourth level cases have also been addressed by these upgrades. As N-1 overloads exist on the Five Mile Rd – Homer Hill circuits, N-1-1 overloads on these same lines are not indicated.
When considering the as drafted definition of BES and the as drafted revisions to the TPL standards (TPL-001-2), it is expected that because the overloads on the Five Mile – Homer Hill lines surpasses STE for multiple N-1-1 conditions, that correction of this overload will be required in the future to address the minimum reliability standards. Thus, the A1 plan does not adequately address the N-1-1 reliability issues and is not the preferred plan.
Indeck Olean In Service Out of Service In Service Out of Service Indeck Olean In Service Out of Service Out of Service Out of Service In Service Out of Service Out of Service Out of Service
Table 10: Summary of Remaining N-1 Voltage Needs Identified Following Plan A1 Line Jamestown Winter Winter Outage Element 171 Net Load Peak 2016 Peak 2021 Reconductored ~75-80 MW None Reconductored ~75-80 MW None Reconductored ~100-105 MW Reconductored ~100-105 MW
Table 11: Summary of Remaining N-1 Thermal Needs Identified Following Plan A1 Jamestown Winter Winter Outage Element Net Load Peak 2016 Peak 2021 ~75-80 MW None ~75-80 MW ~75-80 MW ~75-80 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW SW None
Indeck Olean In Service In Service In Service In Service Out of Service Out of Service Out of Service
Line 171 Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored
Table 12: Summary of Remaining N-1-1 Voltage Needs Identified Following Plan A1 Jamestown First Second Winter Winter Element Net Load Outage Outage Peak 2016 Peak 2021 ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW
Out of Service In Service In Service In Service In Service In Service In Service In Service In Service In Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service
Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored
~75-80 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW Table 13: Summary of Remaining N-1-1 Thermal Needs Identified Following Plan A1 Jamestown First Second Winter Winter Element Net Load Outage Outage Peak 2016 Peak 2021 ~75-80 MW None ~75-80 MW None ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW Summer Peak 2016
Indeck Olean In Service Out of Service In Service Out of Service Out of Service Out of Service
Line 171 Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored
7. Solutions to Additional Second Level (A2) Needs As a reminder, the following shows the N-1 low voltages and overloads that were determined to be additional second level needs or A2 needs. A review of the solutions for this level did not initially include the projects discussed in the previous section. As discussed above, the First Level plan (A1) is not adequate to address the future minimum reliability requirements as an N-1-1 loading over STE would still exist following completion of that plan.
Indeck Olean Out of Service Out of Service Out of Service Out of Service Indeck Olean Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service
Table 14: Summary of Voltage Needs Identified in Second Level Cases Jamestown Winter Winter Outage Element Net Load Peak 2016 Peak 2021 ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW
Line 171 Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored
Table 15: Summary of Thermal Needs Identified in Second Level Cases Jamestown Winter Winter Outage Element Net Load Peak 2016 Peak 2021 ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW
7.1. Dunkirk Area Low Voltages and Frontier Overloads The previous section described the recommended correction for low voltages in the Dunkirk area and overloads on the #181 and #180 circuits. Only one substantial difference exists between the First level needs and the Second Level needs. This is an overload on the lines between Five Mile Rd and Homer Hill. As the other needs are relatively the same, the recommendations to correct these problems has not changed and are: • • • Addition of 33.3 MVAr capacitor bank on the Dunkirk 115kV bus. ($1.3M) Reconductoring of one mile of the Niagara – Gardenville #180 line. ($3.7M) Reconductoring of 14 miles of the Packard – Erie #181 line. ($35M-$40M)
7.2. Homer Hill Area Overloads The only difference between the first level needs and the second level needs is the overloads between Five Mile Rd and Homer Hill. In the cases with Indeck Olean out of service, the lines between Five Mile Rd and Homer Hill (in this study numbered #163 and #164) were overloaded for an outage of the parallel line or a stuck breaker at Five Mile Rd. This overload surpassed STE in many of the cases and was present in both 2016 and 2021. While the loading was more severe in the summer, it was still found to be over LTE in the winter. As the problem is found for a single element outage in a level two case, correction is recommended. For an N-1-1 outage of the 345kV line between Five Mile Rd and Stolle, followed by an outage of one of the 115kV lines between Five Mile and Homer Hill, the remaining line between Five Mile and Homer Hill would overload N-1-1 outages of line #171, #67 and #996 instead of line #37 also caused loading on lines #163 or #164 It was also found that in cases with Indeck Olean in service, an N-1-1 outage of Indeck Olean followed by an outage of line #163 would result in line #164 being above its STE rating. These lines are on the same double circuit structures for the entire 7.4 miles between Five Mile and Homer Hill. They are currently 336 ACSR conductor. Screening several options only resulted in one acceptable alternative, reconductoring of the lines. Testing showed that reconductoring with a 556 ACSR conductor would only reduce the overload to about 85% of LTE, thus not providing for the future capability that would likely be needed over the 40 or 80 year life of the line. At least a 636 ACSR conductor is recommended, but to insure adequate future capacity and to align with the National Grid standard sizes, 795 ACSR is preferred. It was also noted that this project would result in some improvement to the area voltages and that the larger the conductor size, the greater this improvement. The expected cost of this project, based on using a 795 ACSR conductor, is $17M$19M, depending on the conductor used and is expected to take 5-6 years to implement. Opportunities to separate the lines onto separate structures will be reviewed, but it is expected that the alternative will be cost prohibitive and would need additional, difficult to obtain right of way. The cost for this variation is $27M. Because the overload would develop immediately upon completing Five Mile Rd, this reconductoring should be completed concurrently with Five Mile. Review of Dunkirk Mothball Notice – Part 2 27
7.3. N-1 and N-1-1 System Results for Second Level Plan (A2) The tables below summarize the N-1 and N-1-1 issues that remain following completion of the recommended projects. The recommended projects to address the Second Level needs include: • • • • Addition of 33.3 MVAr capacitor bank on the Dunkirk 115kV bus. ($1.3M) Reconductoring of one mile of the Niagara – Gardenville #180 line. ($3.7M) Reconductoring of 14 miles of the Packard – Erie #181 line. ($35M-$40M) Reconductoring of the two 115kV lines between Five Mile Rd and Homer Hill, approximately 7.4 miles in length. ($17M-$19M)
Indeck Olean In Service Out of Service In Service Out of Service
Table 16: Summary of Remaining N-1 Voltage Needs Identified Following Plan A2 Line Jamestown Winter Winter Outage Element 171 Net Load Peak 2016 Peak 2021 Reconductored ~75-80 MW None Reconductored ~75-80 MW None Reconductored ~100-105 MW Reconductored ~100-105 MW
Indeck Olean In Service Out of Service In Service Out of Service Indeck Olean In Service In Service In Service In Service Out of Service Out of Service Out of Service Out of Service In Service In Service In Service In Service In Service In Service In Service In Service Out of Service Line 171 Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored
Table 17: Summary of Remaining N-1 Thermal Needs Identified Following Plan A2 Line Jamestown Winter Winter Summer Outage Element 171 Net Load Peak 2016 Peak 2021 Peak 2016 Reconductored ~75-80 MW None Reconductored ~75-80 MW None Reconductored ~100-105 MW None Reconductored ~100-105 MW None
Table 18: Summary of Remaining N-1-1 Voltage Needs Identified Following Plan A2 Jamestown First Second Winter Winter Element Net Load Outage Outage Peak 2016 Peak 2021 ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW 66 ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW
~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW Table 19: Summary of Remaining N-1-1 Thermal Needs Identified Following Plan A2 Jamestown First Second Winter Winter Element Net Load Outage Outage Peak 2016 Peak 2021 ~75-80 MW None ~75-80 MW None ~100-105 MW None ~100-105 MW ~100-105 MW ~100-105 MW ~100-105 MW
Indeck Olean In Service Out of Service In Service Out of Service Out of Service Out of Service Out of Service
8. Solutions to Additional Fifth Level (A5) Needs As discussed in section 3.1, plans are developed within this report for the First Level, Second Level and Fifth Level needs. This section examines the options for the Fifth level. This level plan will need to address all N-1 and N-1-1 issues found in the first and second level cases, with the N-1-1 issues driving many of the recommendations. The issues requiring correction are shown in the following tables. The results in these tables do not include any of the upgrades discussed in previous sections. From a desktop review of the needs that require correction, four separate solution sets were developed. From the analysis for the two sets of N-1 plans discussed in earlier sections of this report (A1 and A2 plans), it can be seen that nearly all of the N-1-1 issues have been addressed; only a few N-1-1 low voltage issues remain. The A2 plan was used as the starting point for one of the fifth Level solutions, with additional projects added to address the remaining issues; this new option is referred to as the A5-1 plan.
The second solution set reviewed for this level attempted to address this by starting with a new 230kV path from Packard to Gardenville and then adding in additional projects to address the remaining issues; this option is referred to as the A5-2 plan. The earlier analysis also showed that many of the overloads and low voltages could be traced back this option is referred to as the A5-3 plan. The fourth option reviewed the addition of a new 345kV line from a point called Dysinger to Stolle; this option is referred to as the A5-4 plan.
Indeck Olean In Service In Service In Service In Service Out of Service Out of Service Out of Service Out of Service
Indeck Olean In Service In Service In Service In Service In Service In Service In Service In Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service
Table 20: Summary of Voltage Needs Identified in First and Second Level Cases Line Jamestown Winter Winter Outage Element 171 Net Load Peak 2016 Peak 2021 Reconductored ~75-80 MW Reconductored ~75-80 MW Reconductored ~75-80 MW Reconductored ~75-80 MW Reconductored ~75-80 MW Reconductored ~75-80 MW Reconductored ~75-80 MW Reconductored ~75-80 MW Table 21: Summary of Thermal Needs Identified in First and Second Level Cases Jamestown Winter Winter Outage Element Net Load Peak 2016 Peak 2021 ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW
~75-80 MW ~75-80 MW ~75-80 MW
Line 171 Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored
Indeck Olean In Service In Service In Service In Service In Service In Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service Out of Service
Line 171 Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored Reconductored
Table 22: Summary of N-1-1 Voltage Needs Identified in First and Second Level Cases Jamestown First Second Winter Winter Element Net Load Outage Outage Peak 2016 Peak 2021 ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW ~75-80 MW
Indeck Olean Out of Service
Table 23: Summary of N-1-1 Thermal Needs Identified in First and Second Level Cases Line Jamestown First Second Winter Winter Element 171 Net Load Outage Outage Peak 2016 Peak 2021 Reconductored ~75-80 MW
8.1. Second Level Solution to Fifth Level Needs (A5-1) Earlier in this study, a set of upgrades was recommended to address the second level N-1 problems (A2). This option for a fifth level solution (A5-1) started with these upgrades and added additional projects to address the remaining N-1-1 issues. The remaining N-1-1 issues were low Gardenville and Huntley 230kV voltages for N-1-1 outages The recommended projects to address the Second Level needs and the stating point for this fifth Level solution includes: • • • • Addition of 33.3 MVAr capacitor bank on the Dunkirk 115kV bus. ($1.3M) Reconductoring of one mile of the Niagara – Gardenville #180 line. ($3.7M) Reconductoring of 14 miles of the Packard – Erie #181 line. ($35M-$40M) Reconductoring of the two 115kV lines between Five Mile Rd and Homer Hill, approximately 7.4 miles in length. ($17M-$19M)
Review of the remaining issues started using a 2021 summer peak case with Indeck Olean out of service. It was found that the remaining issues are low voltages. An attempt was made to address them with the addition of capacitor banks. Very few locations are left to add blocks of reactive compensation to the transmission system, as it is unwise to add more than one capacitor bank to any single bus section. The first two proposed additions were at the Huntley 115kV bus and the Dunkirk 115kV bus. With these additions, all voltages and thermal overloads for N-1-1 conditions in the second level cases have been mitigated to an acceptable point. The few remaining N-1-1 low voltages are in fourth level cases, which do not require correction. The complete summary of area performance is in the following tables. Thus the complete option for the Fifth Level Needs is: • • • • • Addition of two 33.3 MVAr capacitor banks on the Dunkirk 115kV bus. ($2.5M) Reconductoring of one mile of the Niagara – Gardenville #180 line. ($3.7M) Reconductoring of 14 miles of the Packard – Erie #181 line. ($35M-$40M) Reconductoring of the two 115kV lines between Five Mile Rd and Homer Hill, approximately 7.4 miles in length. ($17M-$19M) Addition of a second 75 MVAr capacitor bank on the Huntley 115kV bus ($1.4M)
The expected cost of this set of projects is $60M-$67M.
Indeck Olean In Service Out of Service In Service Out of Service Indeck Olean In Service Out of Service In Service Out of Service Indeck Olean In Service Out of Service In Service Out of Service Out of Service Out of Service
Table 24: Summary of Remaining N-1 Voltage Needs Identified Following Solution A5-1 Line Jamestown Winter Winter Summer Outage Element 171 Net Load Peak 2016 Peak 2021 Peak 2016 Reconductored ~75-80 MW None Reconductored ~75-80 MW None Reconductored ~100-105 MW None Reconductored ~100-105 MW None Table 25: Summary of Remaining N-1 Thermal Needs Identified Following Solution A5-1 Line Jamestown Winter Winter Summer Outage Element 171 Net Load Peak 2016 Peak 2021 Peak 2016 Reconductored ~75-80 MW None Reconductored ~75-80 MW None Reconductored ~100-105 MW None Reconductored ~100-105 MW None Table 26: Summary of Remaining N-1-1 Voltage Needs Identified Following Solution A5-1 Jamestown First Second Winter Winter Element Net Load Outage Outage Peak 2016 Peak 2021 ~75-80 MW None ~75-80 MW None ~100-105 MW None ~100-105 MW ~100-105 MW ~100-105 MW
Table 27: Summary of Remaining N-1-1 Thermal Needs Identified Following Solution A5-1 Line Jamestown First Second Winter Winter Summer Element 171 Net Load Outage Outage Peak 2016 Peak 2021 Peak 2016 Reconductored ~75-80 MW None Reconductored ~75-80 MW None Reconductored ~100-105 MW None Reconductored ~100-105 MW None
8.2. New 230kV Line Solution (A5-2) This option examined the impact of adding a new 230kV line to the area. It is expected that obtaining the necessary right of way to construct a new line between Niagara or Packard and Gardenville would be very difficult. So a plan was developed that would utilize existing right of way in a new way. Today three 115kV lines travel between the Niagara/Packard area and either Gardenville or Erie, lines #180, #181 and #182. Each of these lines is on double circuit towers. The fourth line sharing the double circuit towers with these three is a de-energized retired in place circuit. The proposed plan to construct a new 230kV line is to remove one of the two double circuit tower lines and replace it with a new single circuit 230kV line. This will result in the removal of the retired in place circuit and elimination of one of the three energized 115kV lines. All analysis on this option was done assuming no more than three of the four capacitor banks at Gardenville were in service. From this, it can be concluded that selection of this option would allow a reduction in the number of Gardenville capacitor banks. 8.2.1. 115kV Line Impacts This plan will require the reconnection of the existing 115kV lines in a new configuration. Two configurations are available, either a Packard – Gardenville circuit and a Niagara – Erie circuit or a Packard – Erie circuit and a Niagara – Gardenville circuit. For purposes of this study, the option for a Niagara – Erie and a Packard – Gardenville circuit was studied. If an engineering or commercial reason exists to consider the other alternative, further study work would be required to confirm that it would be acceptable. 8.2.2. Niagara – Packard 230kV Line Impacts
An operating exception exists on all lines connected to Niagara that allows their post-contingency loading to be up to the STE limit, as generation reduction at Niagara can be done to reduce the loading. Therefore, this overload is noted in the tables below, but is considered acceptable. It is expected that this option would make the predicted overload more common in real time system operation. If it is decided that this overload is not acceptable, a desktop review has suggested three alternatives. The first is to reconductor the line, it is currently limited by 3.4 miles of 1431 ACSR conductor. This option would also likely require the replacement of terminal equipment at Niagara. The second is to separate lines #61 and #64 onto separate towers. They are on the same towers for about 1.4 miles. The third is to extend the new 230kV line to Niagara instead of Packard. It is expected that the third option will be most difficult and the first option would be the least impactful, however engineering review of all three would be necessary.
8.2.3. Five Mile – Homer Hill Overloads During initial testing of this option, it was confirmed that the new 230kV line would have no impact on the post-contingency overloads on the Five Mile – Homer Hill circuits. With Indeck Olean out of service, an outage of one of the lines or a stuck breaker contingency at Five Mile Rd would result in the other line surpassing STE. To address this, the option to reconductor these lines was include in this solution set. 8.2.4. Remaining Voltage Problems Initial testing of this option also determined that following the addition of the 230kV line and the Five Mile – Homer Hill reconductoring, one additional low voltage concern still exists.
These low voltages are similar to those discussed earlier in this report and are corrected by the addition of a single 115kV capacitor bank at Dunkirk. 8.2.5. Results The following tables show the result of testing with the proposed solution applied. The solution includes the following. • • • Addition of 33.3 MVAr capacitor bank on the Dunkirk 115kV bus. ($1.3M) Reconductoring of the two 115kV lines between Five Mile Rd and Homer Hill, approximately 7.4 miles in length. ($17M-$19M) Reconfiguration of the existing right of way between Packard and Gardenville such that one 115kV line and one de-energized line are removed, the remaining two 115kV lines are reconfigured and a new 230kV line is added. ($75M)
The expected cost of this set of projects is $93M-$95M. Recall that because of the operating exception that exists at Niagara, the loading over LTE but less than STE on the lines connected to Niagara shown in the table below is acceptable. Most of the low voltages shown in the tables could be addressed by the addition of a second 115kV capacitor bank at Dunkirk. However, addressing these was not required as they are for N-1-1 conditions with Jamestown at ~100 MW, which would be addressed by a sixth level plan. The loading over STE for N-1-1 conditions on #141 and #142 also does not require correction as it would only need to be addressed in a sixth level plan.
Indeck Olean In Service Out of Service In Service Out of Service Indeck Olean In Service Out of Service In Service Out of Service Out of Service Out of Service Indeck Olean In Service Out of Service In Service In Service In Service Out of Service Out of Service Out of Service Out of Service Out of Service
Table 28: Summary of Remaining N-1 Voltage Needs Identified Following Solution A5-2 Line Jamestown Winter Winter Summer Outage Element 171 Net Load Peak 2016 Peak 2021 Peak 2016 Reconductored ~75-80 MW None Reconductored ~75-80 MW None Reconductored ~100-105 MW None Reconductored ~100-105 MW None Summer Peak 2016
Table 29: Summary of Remaining N-1 Thermal Needs Identified Following Solution A5-2 Line Jamestown Winter Winter Outage Element 171 Net Load Peak 2016 Peak 2021 Reconductored ~75-80 MW Reconductored ~75-80 MW Reconductored ~100-105 MW Reconductored ~100-105 MW Reconductored ~100-105 MW Reconductored ~100-105 MW
Summer Peak 2016 Summer Peak 2021
Table 30: Summary of Remaining N-1-1 Voltage Needs Identified Following Solution A5-2 Line Jamestown First Second Winter Winter Element 171 Net Load Outage Outage Peak 2016 Peak 2021 Reconductored ~75-80 MW None Reconductored ~75-80 MW None Reconductored ~100-105 MW Reconductored ~100-105 MW Reconductored ~100-105 MW Reconductored ~100-105 MW Reconductored ~100-105 MW Reconductored ~100-105 MW Reconductored ~100-105 MW Reconductored ~100-105 MW
Table 31: Summary of Remaining N-1-1 Thermal Needs Identified Following Solution A5-2 Line Jamestown First Second Winter Winter Element 171 Net Load Outage Outage Peak 2016 Peak 2021 Reconductored ~75-80 MW None Reconductored ~75-80 MW None Reconductored ~100-105 MW None Reconductored ~100-105 MW Reconductored ~100-105 MW Reconductored ~100-105 MW
8.3. Addition of Transformation at Stolle Rd (A5-3) A review of the N-1 and N-1-1 issues found within this study indicated that many of the concerns started with outages in the Stolle area, resulted in low voltages in the Stolle area or were related to reduced flow into Stolle. This option attempts to address these concerns by reinforcing the Stolle area with new transformation. Initially, this option started with a single 345/230kV transformer, which was in addition to the two 345/115kV transformers that exist today. Then testing was done with various combinations of one or two 345/230kV transformers and/or one or two 230/115kV transformers. There are eight possible combinations of one or two transformers. For each combination, LTC settings were adjusted to hold all voltages to an acceptable level and to control reactive power flows. To determine if this option would be effective to correct the area concerns, two N-1-1 contingencies were tested using the summer 2021 case with Indeck Olean out of service and Jamestown’s net load at ~75 MW. The N-1-1 contingencies tested were an outage of either line #37 or line #66 followed by the 79/80 double circuit tower outage.
Therefore, for this testing, the #37 line outage is an outage of the Homer City – Five Mile Rd section or the Five Mile Rd – Stolle section of the line only. For the transformers, a size similar to the new National Grid 230/115kV transformers at Gardenville and the existing Niagara 345/230kV transformers was selected These results would be affected by variations on these sizes. As each variation seemed to result in an acceptable response, the next test performed was an N-1 double circuit tower outage of lines #180 and #182.
Because of this, this option will need to include reconductoring of that line. Table 32: Remaining Concerns for Indicated Contingency 345/230kV 230/115kV #37+ #66+ 180+182S Transformers Transformers 79+80 DCT 79+80 DCT
Testing was also done to review the impact that the addition of Stolle transformation would have on the overloads between Five Mile Rd and Homer Hill. The new transformation does not reduce the overload and may result in some increases in the overload for some of the N-1 and N-1-1 conditions. Next testing was done on the case with a 345/230kV transformer, the Five Mile – Homer Hill lines reconductored and line #181 reconductored. It was found that for a Review of Dunkirk Mothball Notice – Part 2 40
This was still not acceptable so a Dunkirk capacitor bank would need to be added. Based on the results of this screening, this option would need to consist of the following projects. The addition of a single 345/230kV transformer could be replaced by a 230/115kV transformer. • • • • Addition of a 345/230kV transformer at Stolle Addition of 33.3 MVAr capacitor bank on the Dunkirk 115kV bus. Reconductoring of the two 115kV lines between Five Mile Rd and Homer Hill, approximately 7.4 miles in length Reconductoring of 14 miles of the Packard – Erie #181 line
This option is basically the same as the option discussed in section 8.1, only in place of the simple addition of capacitor banks at Dunkirk and Huntley, a complicated project to add a 345/230kV transformer to Stolle is added. The addition of the Stolle transformer does not mitigate the need for any of the other projects, except the minor reconductoring of line #180. Because of this, this option will be much more expensive and complicated than the option in section 8.1. For this reason, this option is not considered further. As National Grid does not own Stolle Rd, it was not possible to complete investment grade cost estimates for this option, it was only assumed that the cost of the two capacitor banks would be less than the transformer addition. 8.4. Addition of a Dysinger – Stolle 345kV Line (A5-4) This option examines the impact of adding a 345kV circuit from Stolle Rd north to a point referred to as Dysinger. This is a point on the Niagara – Rochester 345kV lines where the Robinson – Stolle 230kV line #66 crosses the right of way and where one of the 345kV lines from Niagara turns and heads north to Somerset. For purposes of this study, it was assumed that the new line would connect only to the Niagara – Rochester 345kV line #2 (neither of the other lines connected to Somerset), via a three breaker ring station. It is also assumed that the 345kV at Stolle Rd would have to be expanded to a four breaker ring configured in such a way that no stuck breaker contingencies would result in an outage to either both transformers or both lines. A straight bus configuration with two bus tie breakers would also be acceptable. Screening of this option was started by reviewing the loading on the Five Mile – Homer Hill 115kV circuits. It was found that for an outage of one line, the other would overload to 110% of its STE rating. This is an increase above what was discussed earlier. Thus, this option would also require a reconductoring of both of these circuits. Following the addition of the reconductoring, the next outage screened was a double circuit tower outage of 230kV lines #73 and #74. For this outage, the 230kV voltage at Dunkirk would fall to 93.7%. As discussed earlier, this would require the installation of a capacitor bank at Dunkirk. It was also found that for an N-1-1 outage of a Dunkirk transformer (either one) followed by a Dunkirk bus fault (either one), the 115kV voltage at Dunkirk would be below the load shed limit. The solution to this discussed above is a second Dunkirk capacitor bank. Following these upgrades, all voltages and loadings would be within acceptable limits. However for an N-1 outage of lines #180 and #182 (double circuit tower outage), line Review of Dunkirk Mothball Notice – Part 2 41
#181 would continue to load to 98% of LTE. It is expected that this would need to be addressed in future years. This plan would thus consist of: • • • Addition of two 33.3 MVAr capacitor banks on the two Dunkirk 115kV bus sections. ($2.5M) Reconductoring of the two 115kV lines between Five Mile Rd and Homer Hill, approximately 7.4 miles in length. ($17M-$19M) Addition of a new 345kV line from a new three breaker ring bus constructed at the point commonly referred to as Dysinger to Stolle with expansion of the Stolle 345kV bus to a four breaker ring.
Based on a $3M to $10M per mile cost of 345kV construction, cost of only the new 345kV line (estimated to be at least 22 miles long) would be over $70M, possibly as high as $200M. Thus expected cost of this complete set of projects is in excess of $90M possibly as high as $220M. As this cost is much higher than the other options considered, this option is not the recommended approach for the area. In addition to the high cost, it is expected that if this option were selected, line #181 would still have to be reconductored at some point outside the study horizon, further increasing the cost.
Indeck Olean In Service Out of Service In Service Out of Service Indeck Olean In Service Out of Service In Service Out of Service Indeck Olean In Service Out of Service In Service Out of Service Indeck Olean In Service Out of Service In Service Out of Service
Table 33: Summary of Remaining N-1 Voltage Needs Identified Following Solution A5-4 Line Jamestown Winter Winter Summer Outage Element 171 Net Load Peak 2016 Peak 2021 Peak 2016 Reconductored ~75-80 MW None Reconductored ~75-80 MW None Reconductored ~100-105 MW None Reconductored ~100-105 MW None
Table 34: Summary of Remaining N-1 Thermal Needs Identified Following Solution A5-4 Line Jamestown Winter Winter Outage Element 171 Net Load Peak 2016 Peak 2021 Reconductored ~75-80 MW Reconductored ~75-80 MW Reconductored ~100-105 MW Reconductored ~100-105 MW Table 35: Summary of Remaining N-1-1 Voltage Needs Identified Following Solution A5-4 Line Jamestown First Second Winter Winter Element 171 Net Load Outage Outage Peak 2016 Peak 2021 Reconductored ~75-80 MW None Reconductored ~75-80 MW None Reconductored ~100-105 MW None Reconductored ~100-105 MW Table 36: Summary of Remaining N-1-1 Thermal Needs Identified Following Solution A5-4 Line Jamestown First Second Winter Winter Element 171 Net Load Outage Outage Peak 2016 Peak 2021 Reconductored ~75-80 MW None Reconductored ~75-80 MW None Reconductored ~100-105 MW None Reconductored ~100-105 MW
9. Non-Wires Alternatives The following sections discuss how non-wires alternatives (NWA), such as demand side management or distributed generation might be used to address the needs discussed within this report. For purposes of this review all analysis was performed with a summer 2016 case with Indeck Olean out of service and Jamestown at 75-80 MW (second level case). It was found that all summer problems were worse than those observed in the winter were. 9.1. Low Voltage Concerns As discussed within the earlier sections, many of the plans include the addition of capacitor banks to support post contingency voltages. It is expected that the addition of two permanent capacitor banks at Dunkirk and a second capacitor bank at Huntley could all be in service by spring 2014. In addition, the mobile capacitor banks can and are utilized in western NY to support the system while these permanent upgrades are put into place. Because of these points, review of NWA to address the voltage needs or to reduce the need to run generation at Dunkirk was not undertaken. It is also expected that the cost to install capacitor banks would be comparable to the annual cost of doing a NWA. 9.2. Overloads on Five Mile – Homer Hill Circuits To review the amount of NWA needed to address this overload concern, a review was performed to find out how much load would have to be reduced in the Homer Hill area to keep the loading on the Five Mile – Homer Hill circuits below LTE for an N-1 stuck breaker at Five Mile Rd. An N-1 outage of one of the lines between Five Mile and Homer Hill would also result in the overload; the stuck breaker was just used for screening, as the overload was slightly worse. First, a test was performed to scale the entire western division down until the problem was corrected. It was found that the load had to be reduced to 62% of its initial value (peak) to correct the loading to 100% of its LTE rating. This suggests that the problem would be present over 1850 hours each summer. Next, only the load between Dunkirk, Falconer, Homer Hill and Gardenville was scaled. This scaling included all customer loads and all municipal loads. It was found that the load had to be reduced to less than 74% of its initial value to correct the overload. Based on these two tests, the use of NWA to address the area concerns was not considered a viable option. The reductions in these various targeted areas were larger than 20% of the total load in the targeted area of need. This value is used as a guideline by National Grid to determine if NWA are viable options as documented in National Grid’s “Guidelines for Consideration of Non-Wires Alternatives in Transmission and Distribution Planning,” Issue 1, approved February 2011. The number of hours of exposure also makes NWA impractical. 9.3. Overloads on Lines #181 and #180 To review the amount of NWA needed to address this overload concern, a review was performed to find out how much load would have to be reduced in the area supplied by lines #180, #181 and #182, including NYSEG’s Erie area, to keep the loading on the Packard – Erie #181 circuit below LTE Review of Dunkirk Mothball Notice – Part 2 44
First, a test was performed to scale the entire western division down until the problem was corrected. It was found that the load had to be reduced to 84% of its initial value (peak) to correct the loading to 100% of its LTE rating. This suggests that the problem would be present over 240 hours each summer. Next, only the load connected to line #181 was reduced. This scaling included all loads at National Grid’s Station 130, Station 124 (served from Youngmann) and Station 58 (served from Youngmann) and customer stations Erie County Water Authority’s (ECWA) Ball Pump Station and Veridian/Calspan. Only about 3 MW of the over 100 MW of load supplied by this line is at these two customer stations. The review also scaled the load at a proposed station at Frankhauser Rd, which is planned to be completed in 2014. Approximately 35 MW of load will be moved to Frankhauser Rd Station from National Grid stations 130 (27%), 124 (9%), 58 (5%), 54 (12%), 224 (17%) and 140 (30%). Today the load at Stations 54 and 140 is supplied by circuits #38 and #39 and Station 224 is supplied by circuits #36 and #37. Initially the load connected to NYSEG’s 34.5kV network, was not scaled. The load at the National Grid distribution and customer stations had to be reduced to reduce the loading on the line below its LTE rating. Next, scaling of the NYSEG 34.5kV network was reviewed.
Based on these tests, the use of NWA to address the area concerns was not considered a viable option. The reductions in the targeted area were larger than 20% of the total load in the targeted area of need. This value is used as a guideline by National Grid to determine if NWA are viable options as documented in National Grid’s “Guidelines for Consideration of Non-Wires Alternatives in Transmission and Distribution Planning,” Issue 1, approved February 2011. The number of hours of exposure also makes NWA impractical. 10. Summary Based on the system analysis and a review of the potential cost of area upgrades, the recommendation is to address all N-1 problems and greatly mitigate the N-1-1 exposure by implementing the A5-1 plan. This plan includes: • • • Addition of two 33.3 MVAr capacitor banks on the two Dunkirk 115kV bus sections. This project should be implemented as soon as possible. ($2.5M) Addition of a second 75 MVAr capacitor bank at the Huntley 115kV switchyard. This project should be implemented as soon as possible. ($1.4M) Reconductoring of the two 115kV lines between Five Mile Rd and Homer Hill, each approximately 7.4 miles in length. This project is recommended to be executed such that it is complete when Five Mile Rd comes into service. If the project cannot be completed by the time Five Mile Rd is completed, a review of the risk associated with the 45
outage/overload and the cost of continued operation of generation at Dunkirk will have to be undertaken to determine when the shutdown of the generation can occur. ($17M$19M) • Reconductoring of one mile of the Niagara – Gardenville #180 line. To facilitate the retirement of the generation as soon as possible, this project is recommended to be implemented such that it is complete at or before Five Mile Rd coming into service. If the project cannot be completed by the time Five Mile Rd is completed, a review of the risk associated with the outage/overload and the cost of continued operation of generation will have to be undertaken to determine when the shutdown of the generation can occur. ($3.7M) Reconductoring of 14 miles of the Packard – Erie #181 line. To facilitate the retirement of the generation as soon as possible, this project is recommended to be implemented such that it is complete at or before Five Mile Rd coming into service. If the project cannot be completed by the time Five Mile Rd is completed, a review of the risk associated with the outage/overload and the cost of continued operation of generation at Dunkirk will have to be undertaken to determine when the shutdown of the generation can occur. ($35M-$40M)
The expected cost of this set of projects is in the range of $60M-$67M based on investment grade estimates with a range of -50% - +200%.
Bill NoJay ProfileUNITED STATES OF AMERICA Dixon.maija.C.release.2016!06!09Dixon.Maija.C.2016.05.26.DETHeroin and OpioidsSUNY Letter -- 6.7.16SUNY Letter -- 6.7.16Transportable Locations 11-18-15DOC052616-05262016134513Active Hate Groups Transportable Locations 11-18-15RJSCB Annual Report FY 2013-14Rochester Schools Modernization ProgramClipping from D&C 1927Engaging Communities Through Solutions Journalism306646129 Dawson Larry Complaint and Affidavit March 31 2016clipping_4762390 (1)Dawson Mortuary opening 1974fLarry R. Dawson - 2.2DHS Media Statement_03_29_20162015 TN Single AuditThe Tennessean Mon Aug 25 2003The Tennessean Thu Dec 29 1960Jason R. HamrickPublic Records Response Letter.4-5
Feb 15 PFeb 15 PSC filing re Dunkirk mothball.pdf by Matthew Leonard12 viewsEmbedDownloadDescriptionCase 12-E-0577 – Proceeding on Motion of the Commission to Examine Repowering Alternatives to Utility Transmission Reinforcements – Estimated Cost of Transmission UpgradesCase 12-E-0577 – Proceeding on Motion of the Commission to Examine Repowering Alternatives to Utility Transmission Reinforcements – Estimated Cost of Transmission UpgradesInterests: Types, Government & PoliticsRead on Scribd mobile: iPhone, iPad and Android.Copyright: Attribution Non-Commercial (BY-NC)Download as PDF, TXT or read online from ScribdFlag for inappropriate contentShow moreShow less
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