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BPMC Jan 27, 2014 1
BEMC WZ \.S0pM Fe -addeot Status tortrad ves > Pod J - 201-0) Bold Dow = why 1 tp duuy else _, Got). uot is (ts cequestiag PP icey — debined ABlete ry “nedering’ Cory — - th Hel Want opbate 0 m_lasses, Never teste? Rada - 68-2 More pack gvaued 6 _audut So operons or_reviad cas B. Opuaine epoct- Bio Day ae (ME meeting CMa.) 708-62 £ Fish Watkin PO Mac 3 oan BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE REGULAR MEETING AGENDA Monday, January 27, 2014 1:30 - 3:30 p.m. Alaska Energy Authority’s Board Room 813 West Northern Lights Boulevard, Anchorage, AK 1, CALL TO ORDER ys ROLL CALL (for Committee members) Bs PUBLIC ROLL CALL (for all others present) 4. PUBLIC COMMENT 5; AGENDA COMMENTS / MOTION FOR APPROVAL 6. OLD BUSINESS A. Telemetry of Bradley Lake into Chugach Load Balancing Area (Res. 2014-01 - action item) ED TD leok oF B. Status report on Power House Controls Upgrade Project (possible action item) Soe 0 C. Kenai Outage Nov. 22,2013 ©4V NEW BUSINESS udget Amendment (action item) B HEA Jn, 17, 2014 Proposed Resolutions (possible action items) = 1D 21 1./Resolution 2014-03 — Repair of Fish Water Release System te A an we ved) A U 2. Resolution 2014-04 — Update Loss Factors Pony {aloe we “ np comms oo wer! 3. Resolution 2014-05 — Legal Counsel Correspondence Distribution €eo pe 2 (cOVOH VO’ eee 4. Resolution 2014-06 — Committee member's invitation to all discussion meetings regarding Bradley Lake project issues 5. Resolution 2014-07 — Project Dispatcher to follow prescribed schedule = NON (ese lun OPERATORS REPORT - COMMITTEE ASSIGNMENTS 10. © ADJOURNMENT To participate by teleconference, dial 1-800-315-6338 and use code 3074#. Bradley Lake Project Management Committee Regular meeting ALASKA ENERGY AUTHORITY Regular Meeting Bradley Lake Project Management Committee Notice is hereby given that the Bradley Lake Project Management Committee will hold a regular meeting on Monda’ January 27, 2014 at 1:30 p.m. For additional information contact Teri Webster. 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 3074#. The public is invited to attend. The State of Alaska (AEA) complies with Title Il of the Americans with Disabilities Act « 1990. Disabled persons requiring special modifications to participate should contact AEA staff at (907) 771-3074 to mak arrangements. Attachments, History, Details Attachments Details BPMC Jan27 Agenda.doc Department: Revision History Category: Created 1/16/2014 4:01:45 PM by tawebster Sub-Category: Modified 1/16/2014 4:01:45 PM by tawebster Location(s): Modified 1/22/2014 8:51:01 AM by tawebster Project/Regulation #: Publish Date: Archive Date: Events/Deadlines: Commerce, Community and Economic Development Public Notices Advisory Committee Meetinc Statewide 1/16/2014 1/28/2014 ALASKA INDUSTRIAL DEVELOPMENT AND EX' BOARD MEETING AUTHORITY 4, \e yo BPMC 1/27/14 First Second First Second, First | Second First Second First Second ‘J PP hee Jes Be [98 Fes [ae ol Kes 9 es OF ena Qos eal Res Roll call from top to bottom ending with Chair load Fishy less Feclors Yes Yes No Yes No Yes / | No | No Golden Valley Electric Association a S VY Homer Electric Association vv a ae |Matanuska Electric Association 4 | F- ad City of Seward ~ WA re Alaska Energy Authority | iF | A go b.\ ned a Municipal Light & Power wy y- az Chugach Electric Association — a 7 a S10 4h by law First | Second 5 9 \- Kes os Roll call from top to bottom ending with Chair Yes Golden Valley Electric Association Homer Electric Association Matanuska Electric Association City of Seward ‘Alaska Energy Authority Municipal Light & Power Chugach Electric Association Next Meeting: xxxx xxXxx XX, XXXX RESOLUTION OF THE BRADLEY LAKE HYDROELECTRIC PROJECT PROJECT MANAGEMENT COMMITTEE RESOLUTION NO. 2014-02 Maintain the Status Quo During the Pendency of the Dispute WHEREAS, on December 8, 1987, the Alaska Power Authority (“APA”), Chugach Electric Association, Inc. (“Chugach”), Golden Valley Electric Association, Inc. (“GVEA”), the Municipality of Anchorage d/b/a Municipal Light and Power (“ML&P”), the City of Seward d/b/a Seward Electric System (“Seward”), and Alaska Electric Generation & Transmission Cooperative, Inc. (““AEG&T”’), and additional parties Homer Electric Association, Inc. (“HEA”) and Matanuska Electric Association, Inc. (“MEA”) entered into the Bradley Lake Hydroelectric Project Agreement for the Sale and Purchase of Electric Power (“Power Sales Agreement”) with the Alaska Energy Authority (“Authority”) (collectively, “Project participants”); and WHEREAS, Chugach, HEA, GVEA, MEA, ML&P, Seward, and AEG&T also entered into the Agreement for the Wheeling of Electric Power and for Related Services (“Services Agreement”) with Chugach; and WHEREAS, HEA, Chugach, GVEA, ML&P, and AEG&T also entered into the Agreement for the Sale of Transmission Capability (“Transmission Agreement”) with HEA; and WHEREAS, the Authority issued Power Revenue Bonds under the Power Revenue Bond Resolution (“Bond Resolution”); and WHEREAS, the Power Sales Agreement, the Services Agreement, the Transmission Agreement, and the Bond Resolution (“Bradley Lake Agreements”), among others, collectively set forth the arrangements, responsibilities, and obligations necessary to secure the benefits of the Bradley Lake Hydroelectric Project (“Project”) for all the Project participants; and WHEREAS, pursuant to Section 13 of the Power Sales Agreement, the Project Management Committee (“PMC”) has been formed for the purposes and with the responsibilities specified by the Bradley Lake Agreements including, without limitation, the responsibility to address disputes arising under the Bradley Lake Agreements; and WHEREAS, HEA entered into the Agreement for the Lease of Facilities (“Lease”) with Chugach wherein Chugach agreed to lease and operate HEA’s transmission line running between the Soldotna Substation and the Quartz Creek Substation (“S/Q Line”); and WHEREAS, the Lease expired on January 1, 2014, and there is a dispute as to the impact the expiration of the Lease may have, if any, on the continuing rights and responsibilities of Chugach to dispatch, operate, maintain, and repair the S/Q Line under the Services Agreement and the other Bradley Lake Agreements (“dispute”); and WHEREAS, Section 12(c) of the Services Agreement provides that “pending resolution of any dispute, each Party shall continue to perform its obligations under this Agreement” requiring the status quo be maintained during the pendency of the dispute; and WHEREAS, on December 12, 2013, the BPMC passed Resolution No. 2013-02 resolving, in relevant part, that the status quo be maintained by stating “Chugach shall continue to operate and maintain the S/Q Line in accordance with Chugach’s responsibilities and obligations under the Services Agreement pending the resolution of the dispute”; and WHEREAS, HEA may have continued to make unilateral changes to its facilities and practices that adversely impact Chugach’s ability to continue to operate and maintain the S/Q Line during the pendency of the dispute; and WHEREAS, HEA’s continued unilateral changes put at risk the ongoing safety, security, and reliability of wheeling Project energy over the S/Q Line and may result in irreparable harm to personnel, Project participants, and utility customers reliant upon a safe, secure, and reliable transmission system for the delivery of Project energy. NOW, THEREFORE, IT IS HEREBY RESOLVED BY THE BPMC AS FOLLOWS: BE IT RESOLVED: All Project participants shall act in good faith to maintain the status quo and permit Chugach to continue to dispatch, operate, maintain, and repair the S/Q Line under the terms of the Services Agreement and the other Bradley Lake Agreements during the pendency of the dispute. BE IT FURTHER RESOLVED: HEA shall not make any further changes to its facilities or practices that adversely impact Chugach’s continuing rights and responsibilities to dispatch, operate, maintain, and repair the S/Q Line during the pendency of the dispute. BE IT FURTHER RESOLVED: Any further unilateral changes put at risk the ongoing safely, security, and reliability of wheeling Project energy over the S/Q Line and may result in irreparable harm to personnel, Project participants, and utility customers reliant upon a safe, secure, and reliable transmission system for the delivery of Project energy. BE IT FINALLY RESOLVED: Pursuant to the Bradley Lake Agreements and this resolution, any Project participant may seek injunctive or other relief from the Superior Court of Alaska for the Third Judicial District to enforce the obligation of all Project participants to maintain the status quo and permit Chugach to continue to dispatch, operate, maintain, and repair the S/Q Line under the terms of the Services Agreement and the other Bradley Lake Agreements during the pendency of the dispute. DATED at Anchorage, Alaska, this 27" day of January, 2014. Chair Secretary RESOLUTION 2014-02- MAINTAIN STATUS QUO PAGE 2 OF 2 CONSENTING AND APPROVING RESOLUTION OF THE BRADLEY LAKE HYDROELECTRIC PROJECT MANAGEMENT COMMITTEE RESOLUTION NO. 2014-01 Telemetry of Bradley Lake into Chugach Load Balancing Area WHEREAS, pursuant to Section 13 of the Bradley Lake Hydroelectric Project Agreement for the Sale and Purchase of Electric Power (the "Power Sales Agreement") dated as of December 8, 1987, by and among the Chugach Electric Association, Inc.(Chugach), Golden Valley Electric Association, Inc., the Municipality of Anchorage d/b/a Municipal Light and Power, the City of Seward d/b/a Seward Electric System, and Alaska Electric Generation & Transmission Cooperative, Inc., and as Additional Parties Homer Electric Association, Inc. (“HEA”), and Matanuska Electric Association, Inc. (as used herein collectively, the "Purchasing Utilities"), and the Alaska Energy Authority (the "Authority" ), the Project Management Committee (the "Committee") has been formed for the purposes and with the responsibilities specified by the Power Sales Agreement; and WHEREAS, pursuant to section 13 (c) (ii) (A) the committee is required to arrange...” for the operation and maintenance of the Project, and the scheduling, production, and dispatch of the Project power...”; and WHEREAS, as of December 31. 2013, HEA began transition from a net requirements customer of Chugach (via the tri-partite agreement) operating within Chugach’s Load Balancing Area; and, WHEREAS, on January 1, 2014, HEA began operating its own Load Balancing Area (LBA) and take on the duties of a Load Balancing Authority; and, WHEREAS Chugach Electric will remain the Project Dispatcher; and, WHEREAS, HEA is the Operator of the Project Power Plant and through various agreements the Project transmission lines south of Quartz Creek; and, WHEREAS, the Project facilities must telemetered out of the HEA LBA and into the Chugach LBA; and, WHEREAS, it is in the best interest of the Project and the interconnected Railbelt grid to accurately account for and allocate electrical losses; and, WHEREAS, the following LBA interchange configuration will minimize the magnitude of required Project loss adjustments, and simplify real and reactive power energy accounting. NOW, THEREFORE, IT IS HEREBY RESOLVED BY THE COMMITTEE as follows: Committee Determination: The Committee has determined that it is in the best interests of the interconnected Railbelt grid, the Purchasing Utilities and their respective customers or members that Project facilities south of Quartz Creek be telemetered out of the HEA LBA and into the CEALBA with the LBA boundary defined by following interchange points: e Bradley Lake MOD 2425 (real and reactive interchange with Diamond Ridge line) Soldotna 115 -69 kV transformer (real and reactive interchange ) Soldotna 115 kV line to Diamond Ridge (real and reactive interchange ) Soldotna 115 kV line to Bernice Lake (real and reactive interchange ) Soldotna LM 6000 generator (real and reactive interchange) Sterling Substation T-1 (Sterling real and reactive ) Quartz Creek Breaker 442 (Quartz to Soldotna 69 kV line) CEA, the Project dispatcher, will continue to schedule energy and capacity, for the participants delivered to CEA, at HEA’s Soldotna Substation, as currently defined in the Bradley Lake “Agreement for the Wheeling of Electric Power and for Related Services. DATED at Anchorage, Alaska, this 27" day of January, 2014. Chair Secretary REs 2014-01 LOAD BALANCING CONSENTING AND APPROVING RESOLUTION OF THE BRADLEY LAKE HYDROELECTRIC PROJECT MANAGEMENT COMMITTEE RESOLUTION 2014-03 Proceed with Repair of the Fish Water Release System WHEREAS, the Bradley Lake Hydroelectric Project FERC permit requires prescribed fish water release flow; and WHEREAS, not meeting the prescribed flow could result in Violations; and WHEREAS, preventing such Violations is a priority of both the Owner (AEA) as well as the BPMC; and WHEREAS, debris over the years has plugged/partially plugged the inlet ports to the fish water release system making the fish water release system inadequate during certain conditions; and WHEREAS, continued failure to act could result in a Violation of the applicable FERC permit as well as placing the Project at risk of an expensive loss of water. NOW, THEREFORE, BE IT RESOLVED, that the BPMC require the Bradley Lake Hydroelectric Project Operator and Maintainer to proceed with the repair of the fish water release system; and BE IT ALSO RESOLVED, that the Operation and Dispatch Subcommittee immediately begin planning to coordinate water usage (drawdown) with the work of the Project Operator. BE IT ALSO RESOLVED, that the Project Dispatcher operate the plant in such a manner as to meet the prescribed drawdown schedule. DATED at Anchorage, Alaska, this 27" day of January, 2014. Chair Secretary CONSENTING AND APPROVING RESOLUTION OF THE BRADLEY LAKE HYDROELECTRIC PROJECT MANAGEMENT COMMITTEE RESOLUTION 2014-04 Resolution to Require Updated Loss Factors WHEREAS, the Bradley Lake Hydroelectric Project Amendment to the Agreement for Sale of Transmission Capability by and among HEA and the Participants states in Section 3(b) that “HEA shall be compensated for line losses, if any, resulting from the power of the Purchasers flowing over the Soldotna Segment;” and WHEREAS, in the same section it is also stated that “The Project Management Committee will determine the amount of line losses and the appropriate amounts and manner of compensation;” and WHEREAS, the current loss curve is dated, contains visual irregularities and fails to match measured losses; and WHEREAS, requirements for unit commitment and the physical location of units on the Kenai Peninsula differs significantly from when the previous curves were calculated; and WHEREAS, electrical laws of current flow dictate that losses in the HEA system occur on more than just the Soldotna Segment; and WHEREAS, HEA, at the January 19, 2012, meeting of the BPMC, requested that the BPMC take up the issue of correcting the currently used loss calculations, and WHEREAS, to date the BPMC has failed to act upon HEA’s request; and WHEREAS, the BPMC’s failure to timely act upon HEA’s request has, in HEA’s opinion, resulted in significant costs being inappropriately imposed upon HEA members for losses created by export energy flows from the Bradley project. NOW, THEREFORE, BE IT RESOLVED, that the BPMC immediately accept the HEA Loss Calculation based upon the June 2012 EPS loss studies or immediately commission a new loss study with a competent engineering firm with experience in loss calculations as well as knowledge of Kenai infrastructure. The loss factor calculations should include reasonable line contingencies as well as generation dispatch and commitment for the Soldotna Segment as well as the adjoining Kenai Infrastructure. DATED at Anchorage, Alaska, this 27" day of January, 2014. Chair Secretary CONSENTING AND APPROVING RESOLUTION OF THE BRADLEY LAKE HYDROELECTRIC PROJECT MANAGEMENT COMMITTEE RESOLUTION 2014-05 Resolution to Require ALL Correspondence from BMPC Legal Counsel to be Distributed to ALL BPMC Members WHEREAS, the Bradley Lake Project Management Committee retains legal counsel for advice and guidance; and WHEREAS, such advice and guidance may be useful for each and every BPMC member in order to make decisions in furtherance of the project good; and WHEREAS, each BPMC member utility pays for BPMC legal counsel through its utility contributions. NOW, THEREFORE, BE IT RESOLVED, that the BPMC require the BPMC Legal Counsel to ensure that any correspondence, notes, or emails created as Legal Counsel to the BPMC, destined for any member, to be distributed to all BPMC members. DATED at Anchorage, Alaska, this 27" day of January, 2014. Chair Secretary CONSENTING AND APPROVING RESOLUTION OF THE BRADLEY LAKE HYDROELECTRIC PROJECT MANAGEMENT COMMITTEE RESOLUTION 2014-06 Resolution to Require Invitation to ALL BPMC Members for Scheduled Sessions of Two or More Members in Which Discussion Involves Bradley Lake Hydroelectric Project Issues WHEREAS, some of the Bradley Lake Project Management Committee Members may meet from time to time to discuss planning, strategies, disputes, as well as other matters where no votes or minutes are taken; and WHEREAS, all BPMC members as well as the AEA should be afforded the benefit of such exchange of ideas; and WHEREAS, the BPMC By-Laws already provide (section 5.11.5) for meetings in which all participants are acting individually as representatives of the Parties to the Agreement and not as the assembled Committee. NOW, THEREFORE, BE IT RESOLVED, that the BPMC require Invitation to all BPMC members as well as the AEA, but not the obligation to attend, for any pre-scheduled meeting of two or more Members in which discussion is substantial and in part to involve Bradley Lake Hydroelectric Project Issues; and BE IT ALSO RESOLVED, the BPMC Chairman as well as each individual Member is tasked with ensuring that requirement of being “substantial” or “pre- scheduled” is not abused. DATED at Anchorage, Alaska, this 27" day of January, 2014. Chair Secretary CONSENTING AND APPROVING RESOLUTION OF THE BRADLEY LAKE HYDROELECTRIC PROJECT MANAGEMENT COMMITTEE RESOLUTION 2014-07 Resolution to Require the Project Dispatcher to Follow the Prescribed Daily / Hourly Schedule Until Such Time as Dynamic Scheduling of Bradley Energy Can Be Implemented WHEREAS, the Bradley Lake Allocation and Schedule Procedures contract requires a weekly schedule be produced and contains procedures to modify and implement said schedule; and WHEREAS, the Wheeling and Related Services Contract Section 8 subpart (a) subsection (iv) states as “Duties for the Dispatcher:” (iv) Coordinating with HEA in order that the Dispatcher and HEA alike will minimize, to the extent reasonably practicable, any potential conflicts between and among (A) HEA's system operations, (B) Chugach's system operations, and (C) the dispatch of Project generation and the provision of services to the Wheeling Utilities in the manner contemplated by this Agreement. And, WHEREAS, not adhering to the weekly / hourly schedule is causing operational problems for the HEA Load Balancing Area; and WHEREAS, the BPMC has passed resolution 2013-04 stating the BPMC’s intention to implement dynamic scheduling for the Project; and WHEREAS, the work to implement dynamic scheduling is not yet accomplished NOW, THEREFORE, BE IT RESOLVED, that the BPMC require the Project Dispatcher to return to the status quo and abide by and operate according to the current established contracts, particularly with respect to The Allocation & Scheduling Procedures Agreement, Section 5, subparts (b), (d), (f) and (g), until such time as the procedures and methods to dynamically schedule the Project can be completed. DATED at Anchorage, Alaska, this 27" day of January, 2014. Chair Secretary ONS | ae) | ||| Te 10. BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE REGULAR MEETING AGENDA Monday, January 27, 2014 1:30 — 3:30 p.m. Alaska Energy Authority’s Board Room 813 West Northern Lights Boulevard, Anchorage, AK CALL TO ORDER ROLL CALL (for Committee members) PUBLIC ROLL CALL (for all others present) PUBLIC COMMENT AGENDA COMMENTS / MOTION FOR APPROVAL OLD BUSINESS A. Telemetry of Bradley Lake into Chugach Load Balancing Area (Res. 2014-01 - action item) B. Status report on Power House Controls Upgrade Project (possible action item) C. Kenai Outage Nov. 22, 2013 NEW BUSINESS A. Budget Amendment (action item) B. HEA Jan. 17, 2014 Proposed Resolutions (possible action items) 1. Resolution 2014-03 — Repair of Fish Water Release System 2. Resolution 2014-04 — Update Loss Factors 3. Resolution 2014-05 — Legal Counsel Correspondence Distribution 4. Resolution 2014-06 — Committee member's invitation to all discussion meetings regarding Bradley Lake project issues 5. Resolution 2014-07 — Project Dispatcher to follow prescribed schedule OPERATORS REPORT COMMITTEE ASSIGNMENTS ADJOURNMENT To participate by teleconference, dial 1-800-315-6338 and use code 3074#. Fishwater Screen Project Calculations Lake level on January 19" — 1152.3’ Lake level January 27" — 1152.8’ — Level has not dropped in 8 days. Current lake volume at 1152.8’ = 448,970 acre ft. Lake volume at 1070’ = 247,706 acre ft. Volume reduction required = 201,264 acre ft. 1 MWh production = 1.075 acre ft. (using May 2013 calculations) Need to produce 187,722 MWh in the next 80 days (Feb 1-April 20) 187,722MWh/ 80 days = 2346 MWh/day = 97 MW/hr Estimated cost to remove the debris if lake level is reduced to 1069’ and mechanical equipment is used to clear a path through the snow and remove the debris is as follows: Cost of equipment and manpower - $585,707 Additional cost of divers to inspect DT and PT screens - $72,000 Total - $657,707 Permit fishwater flow requirements: May 1-12 ramps up from 40 CFS to 100 CFS through September 14 Sept 14 - Nov 2, ramps back down to 40 CFS through April 30 Current fishwater capability — Lake level 1098’ : Manifold #1 flow=36 CFS, Manifold #2= 57 CFS, Total Fishwater Flow = 93 CFS Conclusion — If lake level in 2014 is maintained above 1100’, it is projected the fishwater screen cleaning could be postponed until 2015. We would recommend having some pumping capability. Cost estimates will be provided during the FY2015 budget process. Temporary Pump Cost not to exceed $150,000 (2 x 3000 GPM pumps) ?? Conduct Sonar Study of DT, PT and access road under dam ?? > HEA opnetos repor Bradley Lake Hydro Project Compliance with BPMC Resolution 2013-03 Report from the Operator January 24, 2014 The Bradley BPMC committee passed resolution 2013-03 directing the operator to bring the Bradley Lake Project into compliance with the IMC standards as identified as the IMC Intertie Management Committee’s Railbelt Operating and Reliability Standards, updated October 1, 2013 and in resolution 2013-03 also stated: BE IT FURTHER RESOLVED BY THE COMMITTEE , that the Committee desires that the Operator of the Project to abide by and follow the “Railbelt Operating and Reliability Standards, updated October 1, 2013” in all aspects of the operation of the Project and deliver of energy from the Project; and, BE IT FURTHER RESOLVED BY THE COMMITTEE, that AEA and the Operator make the necessary amendments to the Project Operation and Maintenance Standards and/or Work Rules to accommodate and effectuate he purpose and objective of this resolution as soon as practicable and report to the Committee when the operator is complying with this purpose and objective of this resolution. To comply with that directive the following report is prepared. Due to the short expanse of time between the enactment of the above resolution 203-03 (12 December 2013) and this report (January 27, 2014) this report may be lacking in depth and research, further study may result in additional activities requiring action. In order to comply with the wishes of the BPMC the Operator has identified the following areas where the Bradley Lake Hydro Installation is not in compliance with the standards of the IMC There are likely to be additional areas of non-compliance, but at this time we have identified the following: 1. The Project is required to construct a switchyard at the point of interconnection with the Transmission Provider. 2. Various reporting functions are required throughout the IMC standards. The BPMC is required to direct the Project Dispatcher to immediacy comply with those report requirements. 3. The Project must be made to comply with certain requirements imposed by the Transmission Provider at Bradley Junction. a. Spin Burden b. Studies to provide limitations and guidance for the proper operation of the Project so as “to do no harm” to the Transmission Providers system. c. Identify a means and method to prevent the voltage collapse problem as described by CEA that reportedly can be corrected by CEA having operational control of a Diamond Ridge breaker. d. Operating with common boundaries and metering points “so as not to be a burden” on the adjoining LBA. e. Operating in such a manner as to not cause problems in the adjoining LBA, The first order of business is to identify the nature of the Bradley Lake Project, .i.e. The Project. Bradley Lake is owned by the State of Alaska with a Power Sales Agreement to provide power to various utilities throughout the Alaskan Railbelt. The State of Alaska is not a load serving entity but is a generation Owner or generation entity. From the Standards: The Interconnection Standards for Generation and Transmission are documents developed strictly for the Railbelt. They are based on the principles that were used in the development of "Non-utility Generation Interconnection Standards" in place in the Railbelt utilities at the time of drafting (primarily GVEA and Chugach). These distributions system standards were modified to reflect Generation and Transmission and Generation Interconnection issues. These standards are applicable to entities/equipment, where a single contingency (Class B) could result in the net change of 10 or more MW's of generating capacity or load. This limit is based on our current system bias where loss of a 10 MW unit will cause the system frequency to drop 0.1 Hz. In most of our control centers, this is the level where the first level of frequency alarms are initiated indicating a major system disturbance. Clearly the Project qualifies both as a significant source (>10MW) and is a non-utility generator. So it follows that: These [IMC] standards are applicable to entities/equipment, i.e. Bradley Lake. In table T2-2014 of the IMC Standards AEA (the Owner) is shown to be a Generation Owner and a transmission Owner and in addition from the Glossary of terms an Independent Power Producer is defined as: Any entity that owns or operates an electricity generating facility that is not included in an electric utility’s rate base. This term includes, but is not limited to, cogenerators and small power producers and all other nonutility electricity producers, such as exempt wholesale generators, who sell electricity Since these standards apply as directed by resolution 2013-03 and by the definitions cited above we then look to the next part of the standards: 1. The Project is required to construct a switchyard at the point of interconnection with the Transmission Provider. These Railbelt Standards supersede the previous reliability criteria found in the ASCC documents "ASCC Operating Guides for Interconnected Utilities and Alaska Intertie Operating Guides" and the "ASCC Planning Criteria for the reliability of interconnected electric utilities". Where this document is silent the ASCC documents should continue to be referenced. Looking to the requirements for interconnection contained in Exhibit F Section 5 Interconnection Standards for Railbelt Transmission we find a clear deficiency. The whole standard is too lengthy to be repeated here but a switchyard / substation is required at a minimum (emphasis mine) with full telemetering, and control with a Breaker and /% scheme: From Section 5: These portions of the Interconnection Standards state the minimum interconnection (again my emphasis) requirements and equipment necessary for transmission facilities. Specific requirements for each individual proposed facility may vary, depending on factors such as the location of the interconnection, the number and proximity of adjacent consumers, and the characteristics of the facility proposing to interconnect to the Railbelt system. The standards go on to define metering, control and a long list of required equipment to interconnect to the Transmission Provider (HEA). From page 35 of the Interconnection Standards: IX. Equipment Requirements Summary Table 5 Interconnection Equipment Requirements Summary Equipment Requirement All Installations Approved Disconnect Means Required In/Out Metering Required Interconnection Circuit Breaker Required Undervoltage Protection Required Overvoltage Protection Required Under frequency Protection Required Over frequency Protection Required Ground Fault Protection Required Transfer Trip Capability Required Phase-fault Protection Required Telemetry Capability Required Power Quality Monitoring See Note | Export Power Control Equipment See Note | Voice and Data Communication Capability Required Operational Data Logging Required (See Note 2) Automatic Synchronizing w/ Relay Supervision Required Note 1: Requirements will depend on specific contractual agreements and will be assessed on an Individual basis. Note 2: A digital data logger is required; refer to Subsection 5.3.4.7 for specific requirements. As you can see the requirement is considerable and in order for the operator to comply as soon as practicable. The BPMC must immediately fund preliminary engineering design work required to construct the required substation / switchyard / interface at Bradley Junction. Please see the complete set of Interconnection standards as contained in Exhibit F of the IMC Standards incorporated by reference. From Section 412: } The specific design of the protection system depends on the transmission type, size, and other site-specific considerations. The Provider: must meet Transmission Owner's requirements, and all designs and equipment must conform. to the National Electrical Code, the National Electrical Safety Code, IEEE standards, and all federal, state, local, and municipal codes... (Emphasis mine) / Furthermore during the IMC meeting of January 16 2014 (agenda item E (iii)). Chairman Evans spoke at length arid no fewer than two individual times in reference to the proposed interconnection of the Eklutna Generating Station (EGS) by MEA to the Eklutna Hydro Plant transmission liries Chairman Evans declared that “these standards (the IMC Standards) are the minimums and we must enforce the implementation of these standards”. As the operator of the project HEA. wishes to obey the directive of the BPMC. From Section 413 413 Railbelt System Modifications Any modification to the Railbelt electric grid, such as the installation of additional equipment, reconductoring of all or a portion of the connecting Transmission Owners line, or reconfiguration of Transmission Owners protection systems necessary to permit in-parallel operation with the Railbelt electric grid, will be performed by the Transmission Owner. Where such system modifications are required to allow the interconnection of the Provider's facilities, the Transmission Owner will perform these modifications, providing all labor, materials, and equipment necessary, at the Provider’s expense. .. (Emphasis mine) 1. The Project must comply with the Interconnection Standards for Railbelt Generation when the governors are replaced. When the governors are replaced this summer the project will be required to operate for a 45 day test period. During that test period the Project will need to be 100% backed up as described in the Interconnection Standards for Railbelt Generation as described in Section 200 step 4 (d) page 14. The facility will undergo a trial operating period of the greater of 45 days or the projects declaration of being “commercial”. During this period, Online Reliability must meet or exceed the 12 month rolling average of the remainder of the Railbelt interconnection generating units Online Reliability and have no deleterious effects on CPS1, CPS2 or the Disturbance Control Standards Measures... 2. The Project must be made to comply with certain requirements imposed by the Transmission Provider at Bradley Junction. The first of the overarching goals contained in the Standards: First, these standards set the minimum requirements for interconnection to the System; the local entity at the point of interconnection may have additional or more stringent interconnection standards. I call the BPMC’s attention to the last sentence. The local entity is empowered by the IMC Standards to require “...additional or more stringent interconnection standards ”’. In addition the fifth overarching principal states: Fifth, the interconnecting entity, as a condition of interconnection, shall abide by this and all other applicable Railbelt standards as they may be modified or implemented from time to time. A Balancing Authority having jurisdiction shall ascertain that the new entity agrees to these Standards prior to interconnection or that another entity will absorb the new entity’s obligations as additional obligations to their own. The new entity may have additional obligations imposed by the local Transmission Owner. I call the BPMC’s attention to the last sentence. The Project is required by the IMC Standards to be subject to “additional obligations imposed by the local Transmission Owner” Since the Project is directed to become compliant with the standards and two of the five overarching goals require adherence to requirements imposed by the Transmission Provider, we must look to the local Transmission Owner for their requirements for interconnection. 3. The Project must be made to comply with certain requirements imposed by the Transmission Provider at Bradley Junction. a. Spin Burden HEA/AEEC has its own set of standards (RRO Standards) and these standards, according to the IMC Standards, are applicable to the Project. The Project represents a significant generation resource on the entire grid and in addition represents one of the largest generation installations on the Kenai Peninsula. HEA/AEEC has identified a method where by spin burden is assessed according to size; the Transmission Provider therefore places on the Project a spin burden of 120/84 of HEA’s spin burden (Bradley Peak output divided by HEA peak load). This would be 11 MW * 120/80 or 15.71 (16 MW) under the current spin burden carried by HEA. The project will be required, at all times to carry a spin requirement accordingly. This will be a spin burden to the project itself (Generation entity AEA) and cannot be comingled with spin burden carried by the remaining Railbelt utilities but is separate and distinct from the individual utilities individual spin requirement. This will ensure sufficient spin is carried on the Kenai Peninsula to avoid as far as practicable system blackouts. The carrying of additional spin by the participants on the Project will be allowed once studies have shown that doing so will not cause issues for the Transmission Provider or the Kenai transmission system. In addition Alaska Standard AKRES-001-0 - Reserve Obligation and Allocation applies to generation owners (4.3) Alaska Standard AKRES-001-0 - Reserve Obligation and Allocation R2. _—_‘ Responsibility for Operating Reserve R21 Each Load Serving Entity and/or Generation Owner shall provide, or contract for, Spinning Reserve and Non-Spinning Reserve as required by Section R3 equal to or greater than the Operating Reserve Obligation of the entity. As soon as practicable, but not to exceed four hours, after the occurrence of an incident which uses Operating Reserves, each entity shall restore its Operating Reserve Obligation. 4. The Project must be made to comply with certain requirements imposed by the Transmission Provider at Bradley Junction. a. Studies to provide limitations and guidance for the proper operation of the Project so as “to do no harm” to the Transmission Providers system. From Alaska Standard AKFAC-001-0 — Facility Connection Requirements ...R2. The Transmission Owner’s facility connection requirements shall address, but are not limited to, the following items: R2.1. Provide a written summary of its plans to achieve the required system performance as described above throughout the planning horizon: cae a R2.1.2. Procedures for notification of new or modified facilities to others (those responsible for the reliability of the interconnected transmission systems) as soon as feasible. R2.1.3. Voltage level and MW and MVAR capacity or demand at point of connection... The BPMC must immediately provide budget to fund system studies to identify the Project operational issues and studies to provide guidance as to the correct spin levels allowed at the project, as well as system stability studies to reflect the new and different conditions now present at the project and identify a method and procedure to eliminate control issues with the Transmission Provider to prevent voltage collapse and other system issues caused by the interconnection of the Project. In Looking to the standards in: Alaska Standard AKFAC-002-0 - Coordination of Plans for New Facilities A, Introduction i Title: Coordination of Plans For New Generation, Transmission, and End User Facilities 2. Number: AKFAC-002-0 & Purpose: To avoid adverse impacts on reliability, Generator Owners and Transmission Owners and electricity end- users must meet facility connection and performance requirements. These requirements are spelled out in detail in The Railbelt Standards for Generation and Transmission Interconnection. All Entity's proposing to interconnect and operate within the Railbelt will be required to adhere to these standards. 4. Applicability: 4.1. Generator Owner 4.2. Transmission Owner 4.3. Distribution Provider 4.4. Load-Serving Entity 4.5. Transmission Planner 4.6. Planning Authority AKFAC-002-0 makes it again clear that a generation owner (4.1) must comply with the Railbelt Standards for Generation and Transmission Interconnection. The AEA will be required to comply with these stated standards. In addition AKFAC-002-0 requires the Generation owner to provide evidence of compliance and various studies (Please see AKFAC-002-0 R1.1 through R1.5). 1. The Project must be made to comply with certain requirements imposed by the Transmission Provider at Bradley Junction. a. Identify a means and method to prevent the voltage collapse problem as described by CEA that reportedly can be corrected by CEA having operational control of a Diamond Ridge breaker. In recent discussion with CEA, CEA has made an assertion that during certain system conditions or operational levels of the Project CEA needs to have control of a circuit breaker at Diamond Ridge transmission station. This is not acceptable to the Transmission Provider. The BPMC must provide either a remedial action scheme at the Project to prevent such an occurrence or install additional relaying such that the system will correctly operate without CEA exercising control of the Diamond Ridge Breaker. HEA reserves the right to approve and accept any such scheme proposed. 2. The Project must be made to comply with certain requirements imposed by the Transmission Provider at Bradley Junction. a. Operating with common boundaries and metering points “so as not to be a burden” on the adjoining LBA. Both the RRO standards and those of the IMC require that the adjoining LBA’s operate with common interchange points, with common metering points so as to limit the imposition on the adjoining LBA. HEA has identified those exchange points as Bradley Junction, Soldotna SVC and Quartz Creek. The BPMC must immediately direct the dispatcher of the project to begin using those metering points as required by the Transmission Provider and AKBAL -006-0. There are additional requirements contained in Alaska Standard AKBAL-006-0 - Inadvertent Interchange the dispatcher of the Project must comply with. 3. The Project must be made to comply with certain requirements imposed by the Transmission Provider at Bradley Junction. a. Operate in such a manner as to not cause problems in the adjoining LBA. The Transmission Provider requires that until such time as Dynamic Scheduling of the Project can be implemented, tested and is fully operational according to all the interested parties; that the Project be operated as the current contract requires; to an hourly day ahead schedule. Excursions for system disturbances are allowed but those excursions and deviations from the day ahead schedule should be the exception not the norm. Varying schedules at the Project place an undue burden on the Transmission Providers LBA, requiring constant manual adjustments. These manual adjustments make it difficult, if not impossible, to correctly calculate inadvertent. The action of the Project dispatcher in rapidly varying the scheduled output of the Project is prohibited as identified in: Alaska Standard AKBAL-006-0 - Inadvertent Interchange R.4— Adjacent Balancing Authority Areas shall operate to a common Net Interchange Schedule and Actual Net Interchange value and shall record these hourly quantities, with like values but opposite sign. Each Balancing Authority shall compute its Inadvertent Interchange based on the following: It is impossible to operate with a common Net Interchange Schedule and Actual Net Interchange value if there is no common schedule. Alaska Standard AKBAL-005-0 - Automatic Generation Control R11. Balancing Authorities shall include the effect of ramp rates, which shall be identical and agreed to between affected Balancing Authorities, in the Scheduled Interchange values to calculate ACE. It is impossible to operate with identical and agreed to ramp rates if there is no common schedule. In summary and In accordance with resolution 2013-03 the BPMC is required to provide budget to perform the following as soon as practicable: e Various reporting functions are required throughout the IMC standards. The BPMC is required to direct the Project Dispatcher to immediacy comply with those report requirements. e Preliminary engineering work to design and build a substation at Bradley Junction o Placeholder budget cost for Preliminary engineering work $300,000. e Require the Project to carry a spin burden according to the Transmission Providers interconnect requirement. Immediately fund system studies to clarify the normal operation parameters of the Project. Immediately fund system studies to understand the abnormal operational parameters of the project. Immediately fund system studies to provide for mitigation and control measures required to minimize the impact of the connecting Transmission Provider and neighboring LBA (CEA). Immediately fund studies to eliminate the need for a foreign utility to exercise control on a Breaker within the Transmission providers’ ownership and control Boundary for Project miss-operation. The Project must comply with the Interconnection Standards for Railbelt Generation when the governors are replaced. Agree to and enforce system control boundaries as required by Alaska Standard AKBAL- 006-0 — Inadvertent Interchange. Direct the project dispatcher to immediately conform to AKBAL-006-0 by requiring that the adjoining LBA not place an undue burden on the Transmission Provider’s LBA by random variation in Bradley output schedules. Direct the project dispatcher to immediately conform to the LBA boundaries (Bradley Junction and Quartz Creek as well as the SVC at Soldotna) so as to agree and use common interface points of exchange and metering as required by AKBAL-006-0. Bradley Lake BPMC Meeting December 13, 2013 - January 27th, 2014 Operators Report Unit Statistics: Generation Unit 1 (MWhrs) Unit 2 (MWhrs) Total (MWhrs) December 2013 17,562 20,787 38,349 Hydraulics Avg. Lake Level (ft) Usage (ac ft) Fishwater (ac ft) December 2013 1,163 38,076 2,929 Lake Level —- Jan 22: 1152.3 (level has not declined in 3 days due to rain) Inspections: e Bradley Dam — December 18", no abnormal conditions reported e Spillway Gallery Readings — Lake level 1165’ December 11°", D16 pressure 0.12 psi, action level 0.1 psi Lake level 1162’ December 18'", recheck D16-D22, faulty gauge located and removed from service. The follow-up reading on sample point D16 was 0 psi. ye Maintenance: e Circulating water cooling system make-up valve failed resulting in reduced pump suction pressure. One pump seal overheated and developed minor leakage. The makeup valve was replaced and the pump seal was also replaced. System operation restored to normal. ¢ December 18" - Operators responded to fire alarm in East Duplex. Found one sprinkler head fusible link leaking. Operators secured the system and replaced the sprinkler head. Minor cleanup of carpet and foyer area. Fire system and duplex returned to normal. e The penstock flow monitoring system failed. Contacted vendor and they sent a replacement control board. The failed board was returned to Accusonic for analysis. They determined the internal memory card had failed and would not allow the system to reboot. System functioning normal. Bradley Lake Operator Report Page 1 Projects: e Governor - Engineering of the Emerson control system to replace the failing VA- Tech PLC governor system is on schedule. Emerson is 90% complete with the evaluation of the existing VA-Tech software. The current VA-Tech control philosophy will be used as a base to develop the Emerson control system logic. Emerson recommended adding logic that would allow the Bradley units to operate in either Isochronous mode or droop when the system is in islanded condition. The Ilsochronous mode can be enabled or disabled if on-line testing determines it is not useful. Governor Budget Overview:- $824,000 - FY 2014 Budget - Engineering and wiring contractor Governor Base Scope - a. Engineered Turbine Control System - $275,000 b. LVDT’s for Needle Valves and Dividers - $10,600 c. Installation Design - $81,200 d. Installation Supervision, Commissioning and Start-up - $228,000 e. Update all Units 1 and 2 Hydro Turbine Control System Drawings - $20,000 f. Freight (to Homer, Alaska $15,000 Total price = $629,800 Governor Wiring Contractor — (bid requests not released, Emerson is developing the work scope}. Remaining FY 2014 budget for installation is $195,000. Based on installation costs of the last two projects at Bradley Lake the current wiring contractor installation estimate is $317,280. Additional money of $122,280 will be included in the FY 2015 proposed budget for the installation contractor. Based on the above budget information the O&D committee recommended moving forth with the project on September 12, 2013. A purchase order was issued to Emerson on September 17, 2013. Project Dates — Engineering design review — 3/12-18/2014 (at Bradley Lake) Factory acceptance test (FAT) — 4/21-25/2014 Hardware delivery to Homer Alaska — 6/6/201 Installation start date is 7/1/2014. Twenty one days per unit back to back. (42 days total) Installation start — Unit #1 — 7/1-14/2014, followed by one week of testing. Installation start — Unit #2 — 7/22 - 8/5/2014, followed by one week of testing. e Fire Systems - Bradley personnel are in the process of developing a scope for the communication/computer room Fire Suppression System. The current sprinkler system will be replaced with a system that is acceptable for locations that contain sensitive Computer processors and communication equipment. The scope will also request recommendations to replace or update the analog fire system panels in the facility outbuildings and main fire panel in the control room. There is $290,000 budgeted for this project in FY 2014. Bradley Lake Operator Report Page 2 e Fishwater Screens - Budget estimates and a debris removal plan to clean the fisnwater screens are ongoing. Preliminary contact was made with several prospective vendors to evaluate equipment that is available in the area or that can be shipped to the peninsula if required. Estimated cost to remove the debris if lake level is reduced to 1069’ and mechanical equipment is used to clear a path through the snow and remove the debris is as follows: Cost of equipment and manpower - $585,707 Additional cost of divers to inspect DT and PT screens - 72,000 Total - $657,707 A meeting to discuss fishwater requirements with the various agencies is scheduled for January 23" in Anchorage. Current fishwater requirements: May 1-12 ramps up from 40 CFS to 100 CFS through September 14 Sept 14 — Nov 2, ramps back down to 40 CFS through April 30 Current fisnwater capability — Lake level 1098’ : Manifold #1 flow=36 CFS, Manifold #2= 57 CFS, Total Fisnhwater Flow = 93 CFS Discussion with the various utilities regarding the ability to reduce Bradley Lake level to the required level of approximately 1070’ by May 1* is still ongoing. This should be a topic of discussion at the BPMC meeting. e FY 2015 Budget - The preliminary Bradley Lake FY2015 budget will be presented to the O&D committee this month. Bradley Lake Operator Report Page 3 e Relay and Meter Replacement Overview - Arc Flash Study - ARC Flash study and awareness training is scheduled for February 18-20. This is the final stage of the Bradley Lake Relay and Meter replacement project. Engineers from EPS will be on site to conduct training and place MCC and switchgear ARC Flash labels. Relay and Meter Project Initial Budget and Amendment Relay Engineering and installation budget FY2013- $915,000 Meter Engineering and installation budget FY2013- $92,000 Budget amendment BPMC/O&D FY2014 $410,000 Total budgeted installation costs and bids $1,417,000 EPS/EPC bids and meter costs Purchase configure meters (EPS/HEA Engineering) $92,000 EPS engineering design bid - $559;699 EPS installation, commissioning and project management - $282,163 EPC wiring contract bid $544,813 Total estimated cost after bids $1,478,675 Actual cost of project to date EPS Engineering design $563,659 EPS Outage installation, commissioning $282,017 EPC Wiring , installation, and drawings $424,313 Purchas i meter: 21 Total project cost to date $1,361,327 Remaining Budget $55,673 Trips and Incidents: e January 18" — Unit #1 Speed No-Load rejection of 15.82 MW. Unit #2 responded and pickup up load. System disturbance was minimal. Manually stopped Unit #1 and restarted. Placed in Power Mode and returned control to dispatch. Bradley Lake Operator Report Page 4 Documentation of Governor Project The following is a summary of governor project discussion and reports issued to BPMC and O&D between September 26, 2012 and January 2014. Sept 26, 2012 BPMC — e We have experienced issues with frequency response of the Units. We found that when a frequency event occurred and the unit governor controls put the units into Divider 1 Mode of operation, the units did not respond well. On the 21* we attempted to do “Islanding Testing”. As soon as the tie was opened and the SCADA system sent a signal to the Governor to go into Divider | Mode it became unstable and the test was aborted immediately. Further investigation with VA Tech and Emerson found that VA Tech in their Modbus configuration included a Divider Bias setpoint. Emerson treated this bias as a valve limiter bias and was moving it to 100% when the unit came online. The bias is a tuning value that is set at commissioning of the system and was to remain at 10% fixed value. On the 27" we installed a new version of the Governor program that removed the Divider bias from the Modbus interface. We also removed the logic associated with the Divider bias from the Emerson system. We verified the bias was set at 10% currently. Due to high lake level and system constraints, we have not been able to put the units into Divider | Mode and test their response. e Chair Evans said it sounded reasonable and the operator’s will work the fix as soon as possible, due to more expected storms. September 27, 2012 O& D Committee - ¢ Unit #1 has experienced issues where a “Speed-No-Load” action took place. This is where the all the needle close and the generator breaker will stay closed as well. The relays associated with SNL all check out good. The two working theories are; a loose wire in a termination block causing this maintained signal to drop for a short period of time or that the Governor PLC is overheating. Since the last incident we have kept the Governor cabinet doors open and the SNL action has not occurred again. We are installing permanent fans in the cabinets to help keep the cabinets cool. November 8, 2012 O& D Committee ¢ On November I* we were able to do a limited test of Divider | Mode. We worked with Dispatch to put each unit into Divider 1 Mode and verify that we could ramp each unit up and down. The test was successful. The SCADA controls were returned to normal after the test. On November 5" we experienced a load rejection where the Soldotna line tripped at the Soldotna sub and the Diamond Ridge line was ended at the Thompson sub. This left us in a mini island with only the Homer load. Frequency initially went 61.5 and the units backed down to minimum. Since we were not islanded by SCADA and the remote frequency at Bernice Lake were good, AGC was trying to raise load but local frequency was 60.60. We then took the units to local and back to Speed mode and brought frequency to 60.00 and Dispatch closed back in the line. The units and the frequency did not swing or go unstable even under less than ideal conditions. Bradley Lake Operator Report Page 5 December 13, 2012 O& D Committee On the 28" of November, Unit #2 experienced 2 shutdowns where the needles went closed and the generator breaker stayed closed in. We identified that in each of these events there was a remote rack communications failure. The loss of communication to the remote racks (in the hydraulic cabinets) caused the needles to close but not trip the unit. We have not seen any repeats of this since the 28". We continue to keep the control room temperature around 65 degrees with the cabinet doors open and fans blowing into each cabinet. Since doing this we have not seen any problems with Unit #1. Larry (HEA) states that the Governor PLC in the Governor Cabinet is being kept at 65 degrees which has alleviated the problems with Unit | cold junction solder failure. He states that there are no longer any spare parts for the PLC and attempts to repair the MOB in place are usually unsuccessful January 10, 2013 O&D Committee On December 17, we experienced another shutdown event with the governor on Unit #1. This is the first one we have seen on Unit #1 since we opened the cabinet doors and installed fans. We have determined that this is not a priority issue. The link is being lost. The hardware is outdated and parts are not available. The vendor has been slow to respond to our inquiries and appears to be uninterested in providing support on this outdated equipment. The governor PLC code is proprietary and therefore we are unable to modify it. January 2013 Larry Jorgensen capital budget detail Governor PLC Replacement We have been experiencing issues where the Governor will shutdown intermittently since January 2012. What we see happen is the needle valves will close but the generator breaker does not trip, in effect it unloads the unit and it then has to be restarted by the Operator to resume operation. In our troubleshooting process, we have tried several things to resolve this with limited success. All of our troubleshooting leads us to believe that the hydraulic cabinet I/O modules are losing their control signal at which point the hydraulic actuators will position to a “safe” position (i.e. closed). Since there is no trip signal present, the generator breaker does not open. We approached VA Tech (the OEM, main office located in Austria) about this problem and they confirmed that if there was a signal loss, this is what would happen. The Governor PLC (a SAT PLC brand) was made in Europe but was bought out by Siemens. VA Tech now uses Allen Bradley PLCs in their North American installations. Each time this unexpected shutdown occurs we are impacting the rest of the Railbelt, gas nominations, and system stability. Dispatch currently is base loading one of the units in Power mode (normal) and then running one unit in Speed mode to minimize MW deviation during needle transitions. Bradley Lake Operator Report Page 6 January 2013 Larry Jorgensen Capital Budget Detail Continued e We then asked for proposals from VA Tech and Emerson to upgrade the Governor PLC, remote I/O links, and improve unit control in the following areas; 1. Better integration with DCS (Modbus IP or better) 2. MW setpoint control through the full range of operation 3. Minimized MW deviation through needle transitions and control mode changes 4. Improved governor control to affect tight system frequency control e We currently are running with the cabinet doors open and the ambient temperature kept down, which seems to help decrese the frequency of the problem. January 10, 2013 O& D Committee e¢ Upgrade Governor PLC — received proposals from Emerson $629,800 & VATECH $750,000. Recommend Emerson for several reasons: the proposal is less, the system will integrate with current DCS, Emerson is a common platform that exists in the Railbelt, this system will replace the PLC and IO, and spare parts are already on site due to other installed Emerson equipment. The plan is to begin engineering work this year and to start installation in the spring of 2014. It is possible to keep using existing outdated system; however, if there is a catastrophic failure, the plant is down until the system is replaced. There are two spare PLC units for the existing system - one spare failed and the other has not been tested. The vendor VATECH is unresponsive to requests for support. January 16, 2013 e Unit #1 experienced another unloading event. The Unit was reset and returned to Dispatch 6 minutes later. Communication to the hydraulic cabinet continues to be the problem. March 20, 2013 BPMC e We have experienced issues with frequency response of the Units after the DCS installation. This was due to coordination issues between the DCS and the Governor which have been corrected. e Weare continuing to see “Unloading” events where the unit will unload itself. The problem has been traced down to the communications between the governor cabinets and the hydraulic cabinets. The OEM does not make or support these parts presently. We have a project in FY 2014 budget to replace the Governor PLC to correct these issues. March 20, 2013 O& D Committee e We have experienced another issue with Unit #1 picking up 10 MW of load without Dispatcher telling it to move. We have gone through the DCS logic and found no differences between the Units. The historian does not show any commands being sent to the Governor. The most likely equipment is the Governor PLC which has had other issues recently and in the past. Bradley Lake Operator Report Page 7 April 2013 O&D Committee Met with Emerson on the Governor project to get things started for this project. We went over the scope of the project and refined dome details of implementation and expectations. We continue to operate with the Kenai Peninsula isolated from Anchorage. Bradley has responded well in spite of steam blows occurring at Nikiski. The line to Anchorage is expected to be out until the end of April. May 2013 O&D Committee The Governor Control Project is also in progress. Work with Emerson is continuing to finalize the Terms and Conditions of the contract. Met with Emerson on the Governor project to get things started for this project. We went over the scope of the project and refined some details of implementation and expectations. September 12, 2013 O&D Committee A meeting was held with Emerson Control on September 3“ to review the turbine governor replacement proposal and required timeline. The Emerson proposal was based on a 39 week delivery schedule. Due to scheduling of the Fishwater Debris project in early June and the need to have the Bradley Generating Units available to allow lake level to be controlled, discussion was held to pursue a governor outage approximately May 1* 2014. That deadline is 33 weeks away from September 16". To facilitate a 33 week design schedule, a PO needs to be generated the week of September 16". Outage proposal timeframe, 21 days per unit. Each unit will be off for about 14 days and allows for 7 days of testing. Approximately 21 days back to back per unit — 42 days total. $824,000 - FY 2014 Budget — Engineering and wiring contractor Governor Base Scope — a. Engineered Turbine Control System - $275,000 b. LVDT’s for Needle Valves and Dividers - $10,600 c. Installation Design - $81,200 d. Installation Supervision, Commissioning and Start-up - $228,000 e. Update all Units 1 and 2 Hydro Turbine Control System Drawings - $20,000 f. Freight (to Homer, Alaska) $15,000 Total price= $629,800 Governor Wiring Contractor — Remaining $195,000 (bid requests not released yet) O&D minutes Sept 12" partial minutes due to equipment problems (minutes amended) Having some issues with Govemor, important to go forward with the Govemor project. Preliminary cost estimate listed in Operator Report. Based on current budget, the committee agreed to go forward with the project. Discussion that $195,000 will not cover a wiring contractor. Additional money will be included in the FY2015 budget. Problems noted with the translation of the minutes. Some of the minutes were lost due to equipment problems reported by the Committee Chair, Mr. Brooks. Bradley Lake Operator Report Page 8 October 10, 2013 O&D Committee e A purchase order was issued to Emerson Water and Power on September 18". A project kickoff meeting is scheduled at the Bradley site the week of October 28". Emerson project engineers and technicians will be on site for several days to walk down and document the governor configuration. e Unit #1 No Load Runback — October 23, 2013. Unit #1 experienced a governor shutdown. The unit rejected to no load due to a re-occurring problem in the turbine governor. VA-Tech has attempted to locate the problem, however the system is obsolete and tech support is limited. Emerson Water and Power is currently designing a replacement governor control system as noted in the project section of this report. December 12, 2013 BPMC ¢ Emerson Control Systems was awarded the Governor Replacement contract. A preliminary kickoff meeting was held on October 29-31" with representatives from Emerson Pittsburgh, PA and Emerson St. Petersburg, Russia. Emerson Monthly Project Updates: Following the project kickoff meeting on October 31, 2013, the project manager for Emerson Water and Power Solutions began forwarding monthly progress updates and items that were pending review of Emerson and/or Bradley Lake personnel. Anyone that would like to receive these project updates can indicate the desire by e-mail to Alan Owens - aowens@homerelectric.com Bradley Lake Operator Report Page 9 BRADLEY LAKE PROJECT MANAGEMENT COMMITTEE MEETING January 27, 2014 Meeting Agenda Item: 7A MOTION: Move to amend the FY14 R&C budget (Schedule D) to increase the Replacement of Electro-Mechanical Relays to $410,000 andadd: 3842, i e 2 Additionally, to reduce the interest earning by $717,000. Move: ye 6 Secon: Food J