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Home My WebLink AboutBPMC Meeting July 9, 2013 1Bradley Lake Project Management Committee meeting ALASKA ENERGY AUTHORITY Regular Meeting Public Notice Bradley Lake Project Management Committee Notice is hereby given that the Bradley Lake Project Management Committee will hold a regular meeting on Tuesday, July 9, 2013 at 8:30 a.m. For additional information contact Teri Webster at 907-771-3074. This meeting will be conducted by electronic media pursuant to AS 44.62.310 at the following location: Alaska Energy Authority Board Conference Room, 813 West Northern Lights Boulevard, Anchorage, Alaska; a teleconference line has been set up for those unable to attend in person. Dial 1-800-315-6338, Enter Code 3065#. The public is invited to attend. The State of Alaska (AEA) complies with Title Il of the Americans with Disabilities Act of 1990. Disabled persons requiring special modifications to participate should contact AEA staff at (907) 771-3074 to make arrangements. Attachments, History, Details Attachments Details Agenda.pdf : Commerce, Community and Departments Economic Development Revision History Category: Public Notices Created 6/26/2013 1:29:41 PM by tawebster Sub-Category: Location(s): Statewide Project/Regulation #: Publish Date: 6/26/2013 Archive Date: 7/10/2013 Events/Deadlines: Sent by ema a3 by Alen OWMS HEA To: Bradley Project Management Committee Subject: Bradley Lake Relay and Meter Replacement Project Update Date: July 9, 2013 Mr. Chairman, This project update is divided in three parts: Part 1 — Project pre-outage design and equipment procurement Part 2 - Outage project management, testing, and commissioning Part 3 - Outage installation wiring contractor Part 1 - Electric Power Systems (EPS) has completed the design demolition and installation package to the 95% complete stage. The budget project to date is under the estimated budget as follows: Estimated Design Budget = $ 659,000 Budget spent to date = $ 401,200 Final estimate including current purchase orders = $ 626,000 Part 1 design phase is projected to be $33,000 under budget. Part 2 — EPS has been selected to perform outage project management, testing and commissioning of the relays, meters, and logic circuits. The budget proposal from EPS detailed man-power requirements for each phase of the outage, and personnel rate schedules. This proposal was reviewed by HEA and is deemed to be an accurate assessment of outage requirements. Part 2 cost estimate = $ 282,162 Part 3 — Request for proposal to secure an outage wiring contractor was released on June 5". The bid proposals received are as follows: Alcan Electric — No proposal received City Electric — Provided partial documentation requested. With the information provided an accurate cost estimate could not be calculated. HEA requested clarification of proposal. They provided an estimate of $350,000 without manpower estimates or documentation to support the proposal. EPC — Provided a comprehensive bid complete with rate charts, schedule, man-power estimate, material estimate, and projected outage cost estimate. EPC proposal = $ 544,813 Page 1 Kachemak Electric — No proposal received NAES -— Provided partial documentation requested. With the information provided an accurate cost estimate could not be calculated. HEA requested clarification of proposal. They provided a verbal estimate on July 4", however they cannot provide a written estimate and documentation until management approval on July 8". NAES verbal proposal = $ 545,000 Proposal Review - After review of the proposals submitted, it is HEA’s recommendation that we award the outage wiring bid to EPC. EPC provided the most in-depth proposal outlining plans to complete each phase of the outage. They were the only vendor to provide documentation to justify the proposal. It should be noted that NAES worked diligently to provide proposal clarification when requested, however the documentation has not been received as of this date. NAES provided a verbal estimate that is comparable to EPC, however it is clear that EPC has a better understanding of the complexity of this project and is better prepared to provide services. Outage cost summary of Part 2 and Part 3 - When EPS was selected as the design engineer, they were requested to provide an estimated outage cost for budgetary purposes. The initial budget estimate = $ 417,000 Part 2— EPS proposal, testing and commissioning= $282,162 Part 3 — EPC proposal, outage wiring installation = $ 544,813 Total projected outage cost = $ 826,975 The difference between the original outage budget estimate and the current proposals equates to a budget shortfall of $ (409,975) Summary - the engineering phase of the relay and meter replacement is projected to be complete within the budget estimate. However, as demonstrated above the outage phase of the project parts 2 and 3 are projected to have a budget shortfall of $409,975 when compared to the original budget estimate. HEA requested a letter of clarification to justify the escalated outage proposals when compared to the initial budget estimate. EPS responded with the clarification and documentation found on page 3 and 4. Page 2 Causes of outage installation cost escalation vs. 2012 budget estimates (response provided by EPS)- Original estimate was prior to an in-depth look at the scope of the replacement. The estimate was based on a direct replacement of relays with no anticipated changes to the plant logic or expansion of the automation system. It was expected the electromechanical relays would be directly replaced with digital relays. In general a large body of “dumb equipment” was replaced by relay logic and communication capabilities. However this will require a much larger body of work during the installation. Replacing the existing relays would have been much more expedient but would have saddled the plant with a large auxiliary relay system that could be consolidated into the relays. Replacing these additional components removed 20-30 duplicate wires with only 5-10 to reconnect, plus design to assure logical equivalency. Thus the installation is more of a relaying system renovation, complete with rerouting and reworking the signaling, rather than just a direct replacement of the old relays. * During the initial stages of the design it was determined that the digital relays could be used to eliminate the need of several auxiliary relays. Moving logic from the older auxiliary relay schemes and into the digital relays required additional logical development around relay capabilities, and will require additional testing and verification steps during installation and commissioning. * During the initial stages of the design it was determined that the digital relays and newly installed DCS system will replace the need for many panel meters. Removal of these meters was added to the scope of work. * The original installation quote did not anticipate the DCS requirement to have a data concentrator, and largely left the communications end of the project up to later work by HEA. Now that many auxiliary systems are being removed the data concentrator points lists and data management are more critical and have become part of the project and can provide sequence of events data. + The estimate did not anticipate a compressed schedule requiring 7 x 12 work days for the installation and commissioning requiring periods of extended overtime. * Original quote did not anticipate synchronizing the E-Gen or auto synchronizing scheme across 115kV breakers. * EPS did not anticipate the level of complexity found in the relay logic schemes for primary and secondary protection. This equired the addition of technicians for testing of data transfers between relays, relay testing schemes, and verification of enhanced primary and secondary protection. + The original installation quote did not include the addition of the metering project. Page 3 ¢ Addition and/or complete change of all 13.8 bus CT’s due to CT ratios. The current CT’s are not precise enough to be compliant with industry standards for arc flash millisecond fault interruption. Additional wire pulls to control room for 13.8 kV backup and breaker fail schemes. Best Regards, Alan Owens Bradley Lake Plant Superintendent Homer Electric Association Page 4