Lyndonville Electric Department Feasibility Analysis Review December 2, 2008 1.

Slides:



Advertisements
Similar presentations
Central Vermont Public Service SOUTHERN LOOP COOLIDGE CONNECTOR Coolidge Connector Community Working Group April 30, 2007.
Advertisements

1 Evaluation Plan for Geotargeted Efficiency Programs November 19, 2008.
Sistan & Balouchestan Electric Power Distribution Company
October 16, 2009 RPG Meeting ERCOT RPG Project Review Update Jeff Billo.
Goshen Area Bus Reconfiguration
DOD Microgrids The Missing Link: Microgrid Applications Michael Dempsey P.E. Burns & McDonnell June 12, 2013 © 2013 Burns & McDonnell. All Rights Reserved.
Building A Smarter Grid Through Distribution Automation DOE Projects OE & OE April 2013 Copyright © 2012 Consolidated Edison Company of New.
1 CLASS webinar 26 March CLASS webinar 26 March 2015 Simon Brooke Electricity North West.
1 BROOKHAVEN SCIENCE ASSOCIATES NSLS – II ASAC Review Conventional Facilities Briefing Electrical Utility Service Dennis Danseglio, P.E. Project Engineer.
Tucson Area Reliability Mike Flores Control Area Operations Tucson Electric Power May 2000.
KURTEN SWITCH PROJECT (BRYAN/ COLLEGE STATION AREA UPGRADES) Technical Advisory Committee December 1, 2005 Transmission Services.
Houston Region Import Capacity Project August 27, 2013 Regional Planning Group Meeting.
1 1 Substation Asset Strategy Kevin Dasso, Senior Director Engineering and Operations IEEE/PES Annual Substations Committee Meeting April 7, 2008.
MARCH 31, 2014 Maine 2014 Outage Coordination CONTAINS CRITICAL ENERGY INFRASTRUCTURE INFORMATION – DO NOT RELEASE.
January 5, 2012 TAC Cross Valley 345 kV Project Jeff Billo Manager, Mid-Term Planning.
ON IT 1 Con Edison Energy Efficiency Programs Sustaining our Future Rebecca Craft Director of Energy Efficiency.
Technical Advisory Committee December 6, 2010 Summary of the CREZ Reactive Study Warren Lasher Manager, Long-Term Planning and Policy.
NOVEMBER 11, 2014 PUBLIC VERSION Maine 2014 Outage Coordination CONTAINS CRITICAL ENERGY INFRASTRUCTURE INFORMATION – DO NOT RELEASE.
AUGUST 19, 2014 PUBLIC VERSION Maine 2014 Outage Coordination CONTAINS CRITICAL ENERGY INFRASTRUCTURE INFORMATION – DO NOT RELEASE.
RiversidePublicUtilities.com Arts & Innovation RiversidePublicUtilities.com Challenges and Solutions for Large-Scale PV Integration on RPU’s Distribution.
© 2000 PACIFICORP | PAGE 1 WYOMING WEST AREA STUDY DECEMBER 2013 Seongtae Kim/Jeremy Viula.
2001 South First Street Champaign, Illinois (217) Davis Power Consultants Strategic Location of Renewable Generation Based on Grid Reliability.
Economic Analyses of FPL’s New Nuclear Projects: An Overview Dr. Steven Sim Senior Manager, Resource Assessment & Planning Florida Power & Light Company.
Transmission planning in Vermont Past, present and future Docket 7081 workshop By Dean LaForest 9/19/05.
Review of progress and future work SQSS Sub Group 2 August 2006 DTI / OFGEM OFFSHORE TRANSMISSION EXPERTS GROUP.
1 Docket 7081 Transmission Planning Information Workshops Third Workshop September 30, 2005 Shaping Demand-Side Resources To Address Transmission Constraints.
1 Entergy Mississippi, Inc. Proposed Transmission Reliability Projects Entergy Transmission Planning Summit New Orleans, LA July 8, 2004.
Over 3,300 Megawatts and Counting Growing and Transforming One of Nation’s Largest DSM Portfolios.
Houston Area Dynamic Reactive Project March 11,
Charles Hosken, General Manager Imperial Irrigation District
Increasing Access to the Grid NIPPC September 8, 2005 Brian Silverstein VP, Operations and Planning Bonneville Power Administration.
JACKSBORO TO WEST DENTON 345-kV PROJECT Presentation to Technical Advisory Committee April 8, 2004 Transmission Services Operations.
Subtransmission Reliability Criteria
Rocky Mountain Power Sub Transmission Five Year Study Findings and Kick Off Attachment K Meeting September 10, 2015.
1 1 1 Central Maine Power Local System Plan Presentation Planning Advisory Committee Meeting December 16, 2009.
© Energy Storage: Addressing Today’s Grid Challenges for Tomorrow’s Energy Demands Brad Roberts Power Quality Systems Director S&C Electric.
1 Entergy Mississippi, Inc. Proposed Transmission Reliability Projects Transmission Planning Summit.
Reliable Power Reliable Markets Reliable People Performance Targets for the Customer Interconnection Process January, 2008.
AFREPREN/FWD Cogen Centre Training Workshop on Cogeneration in Africa
Sacramento Local Agency Formation Commission (LAFCo) Final Environmental Impact Report Amendment of SMUD’s Sphere of Influence and SMUD Yolo Annexation.
Jenell Katheiser Doug Murray Long Term Study Scenarios and Generation Expansion Update January 22, 2013.
LAREDO PLANT RMR EXIT STRATEGY Presentation to Board of Directors March 16, 2004 Transmission Services Operations.
Energy Storage Applications at AEP Emeka Okafor American Electric Power Presentation to SouthWest Electric Distribution Exchange May 7, 2009.
1 Entergy Gulf States, Inc. (Louisiana) Proposed Transmission Reliability Projects Entergy Transmission Planning Summit New Orleans, LA July 10, 2003.
Local Area Study Local Area Study Mitigation Plan Update and Uncertainty Scenarios
Jones Creek Project Submitted to RPG on July 7, 2014 July 22, 2014 Regional Planning Group Meeting.
1 1 1 Central Maine Power Local System Plan Presentation Planning Advisory Committee Meeting November 19, 2008.
June 2008 Windsor-Essex Electrical Service Needs and Solutions.
Demand Response
ESI Alternate Economic Study Process E-RSC Meeting October 21, 2010.
Puget Sound Energy’s Use of RTF Analytical Tools for DSM Valuation Jim Lazar March 4, 2003.
September 1, 2011 TAC Lower Rio Grande Valley Regional Planning Group Project Jeff Billo Manager, Mid-Term Planning.
Update on the North Carolina Transmission Planning Collaborative January 30, 2007 For the North Carolina Utilities Commission and the North Carolina Public.
1 Entergy Mississippi, Inc. Proposed Transmission Reliability Projects Entergy Transmission Planning Summit New Orleans, LA July 10, 2003.
SERC Reliability Corporation 1 SERC RELIABILITY CORPORATION MID-AMERICA RELIABILITY CONFERENCE June 21, 2006 COLUMBUS, OHIO.
1 Entergy Transmission Planning Summit New Orleans, LA July 10, 2003 Generation and Transmission Development in the Southeastern United States.
June 26, 2008 Technical Advisory Committee American Electric Power Service Corporation Presidio Area Reliability Improvements Project James Teixeira Manager,
Response to TAC Questions on PGRR031 TAC– January 28, 2014 Jeff Billo, ERCOT 1.
2006 Preliminary Reliability Study Results Bryan Guy September 7, 2006.
Rocky Mountain Power Five Year Study Findings & Kick Off Meeting
Subteam 1a Competitive Solicitations Framework Working Group Meeting
Affordable Energy Production from Renewable Fuel
Transmission and Distribution Loss Study
DEC System Voltage Planning - June 2018
Electricity Demand Response and Advanced Metering for Integrated Utilities Arkansas Public Service Commission Lonni Dieck AEP May 24, 2007.
Agenda Provide a recap of primary northern route alternatives for the MPRP Describe basis for selected route N5 Overview of analyses performed Description.
California Solar Initiative RD&D PV Integrated Storage: Demonstrating Mutually Beneficial Utility-Customer Business Partnerships Deepak Aswani May 4, 2017.
New England Electricity Restructuring Roundtable September 18, 2009
Presentation transcript:

Lyndonville Electric Department Feasibility Analysis Review December 2,

Lyndonville Electric Department Feasibility Analysis Presentation to the VSPC On June 10,

In 2007 Lyndonville Electric Department (LED) contracted VELCO to analyze both the existing system conditions and the effect of possible load growth within the area. LED invited Central Vermont Public Service (CVPS) to participate in the analysis. On March 26, 2008 the first version of the Transmission and Distribution (T&D) Analysis was released to LED. 3 History

Existing System Reliability Exposure T&D Analysis Performed T&D Alternatives Analyzed Current Status Next steps 4 Presentation Overview

Existing System Configuration 5

6

Existing System Reliability Exposure Loss of the St. Johnsbury Transformer Loss of the X kV Line Note: Loss of the Littleton Source may cause loss of both Lyndonville and St. Johnsbury due to the Undervoltage Sectionalizing Scheme that would trip the St. Johnsbury transformer. 7

Load Levels Analyzed (Note: assumed LED and CVPS will install capacitor banks to improve power factor): –2007: Non-coincident MW Peak at 0.98 p.f. –2012: 46.7 MW at 0.98 p.f MW at Burke new 2% Load Growth on all other 2007 loads –2018: 51.7 MW at 0.98 p.f. 1 MW at Burke New 2% Load Growth on all other 2012 loads –2027: MW at 0.98 p.f. 2% Load Growth on all area 2018 loads 8 T&D Analysis Performed

T&D Alternatives Analyzed Lyndonville Location –Construction of a new 115/34.5 kV Lyndonville Substation. St. Johnsbury Location –Expansion of the existing VELCO 115/34.5 kV St. Johnsbury Substation and construction of a second 34.5 kV line between St. Johnsbury and Lyndonville. 9

Possible Lyndonville Substation Site 10

Lyndonville Substation Project NTA Screening Tool Evaluation Released October 27,

Question 1: Is the proposed project’s cost expected to exceed $2,000,000? Answer 1: Yes – the proposed project has a planning grade estimate of $24.3M based on an assumed end of 2010 in-service date. The project consists of the following (see figure below for one-line): Looping the VELCO K28 line in and out of a new 4-breaker 115 kV ring substation in proximity to the LED No. 2 substation (approximately 9 miles north of the VELCO St. Johnsbury substation). A new 115/34.5 kV 30/40/50/56 MVA LTC transformer Two 10 MVAR 115 kV capacitor banks A new 6-breaker 34.5 kV ring substation, providing a separate breaker position for the LED No.2, Burke Mountain, Pudding Hill, and Industrial Park substation loads. (The number of breakers in the ring may be reduced, resulting in lower costs. The highest cost alternative was chosen for the screening, because if the higher cost project screens out, then a lower cost project will also.) Three 5.4 MVAR capacitor banks 12

13

Question 2: Could elimination or deferral of all or part of the upgrade be accomplished through the use of non-transmission alternatives? Answer 2: Yes, but it would not be cost-effective as demonstrated in the NTA analysis attached. The need for the project and its equipment is driven by current loads with the exception of one of the proposed 5.4 MVAR 34.5 kV capacitor bank additions. This project is primarily needed to provide a redundant supply to both the Lyndonville and CVPS St. Johnsbury loads for loss of the sole VELCO source at the existing St. Johnsbury substation. Loss of the VELCO 115/34.5 kV transformer disconnects the entire Lyndonville and CVPS 34.5 kV system. If the load growth expected for the system could possibly be deferred or eliminated, the need for one of the 5.4 MVAR 34.5 kV capacitor banks may be delayed or removed ($858,000). In addition to the capacitor banks included in the project, the analysis reflected the need for 2 MVAR and 0.66 MVAR of power factor correcting capacitor banks to be added to the Lyndonville and CVPS system at existing load levels. 14

15 Answer 2 Continued: The implementation of non-transmission alternatives to provide a redundant supply to both the Lyndonville and CVPS loads, should the existing VELCO St. Johnsbury source trip, would require 32 MW to meet the current peak loading, and up to 52 MW of future capability, depending on the timing associated with the Burke Mountain ski area expansion. Any generation facility would need to be designed with the ability to stay on-line when its only synchronizing source to the transmission system has been lost and can operate in an islanded situation. If this were possible, and the unit were on-line feeding the entire load at the time the existing St. Johnsbury transformer were lost, then this alternative could possibly remove the need for the new substation. However, this type of operating capability is not typical, and depending on the installation may not be sufficiently robust to allow all customers to remain connected for loss of the tie to the transmission network at St. Johnsbury. In addition, the unit will need to be dispatched and on-line generating to match local load for all hours as if the existing St Johnsbury transformer did not exist. This may be challenging for a fossil-fueled power plant due to emission issues. The generation installation should be designed to make up for loss of one unit at the plant site to achieve a roughly equivalent level of redundancy and robustness provided by the transmission option. This would require the installation of more capacity than needed (likely somewhere between 20 to 50% extra capacity).

16 Question 3: Is the likely reduction in costs (in Question 2 above) from the potential elimination or deferral of all or part of the upgrade greater than $1,000,000? Answer 3: Yes – the entire substation upgrade could be eliminated with 32 MW of distributed resources at existing loads. Notes: 1- These planning grade cost estimates are based on the assumptions made in the “Lyndonville Electric Department Feasibility Analysis” dated March 26, This screening is not indicative of the technical feasibility of alternatives. It only evaluates the costs of NTAs versus the transmission alternative cost.

17 “Back Of the Envelope” NTA: Cost of Proposed Transmission Project= $24.3 M Amount of Load Reduction Necessary with DR = 32 MW Cost of scalable, fossil-fueled generation (lowest cost DG) = $1100/KW (Based on costs used in Southern Loop Analysis in 2007) Cost of 32 MW DG = 32 MW * 1000 * $1100/KW = $35.2 M These costs exclude operating and maintenance costs, which would be significant due to the number of operating hours needed for such an alternative. This analysis also does not include redundant capacity in the event of a generator being unavailable.

18 “Back Of the Envelope” NTA Continued: Should assumption be that DSM could reduce load by 25%, this would still require 24 MW of generation to meet existing load levels. Cost of 24 MW DG with 8MW DSM = $26.4 M Even with assumption that DSM has no societal costs this would still result in $26.4 M of capital investment, with additional generation needed to meet future load growth. Based on these costs the installation of generation as an alternative would not be the least cost alternative given that the recommended transmission upgrade is $24.3 M and accommodates future growth.

Current Status / Next Steps – LED and CVPS continue to work together to determine the best transmission alternative for the study area. – November 30, 2008 – solution selection – March 31, 2009 – implementation strategy and cost allocation Questions and/or Comments 19