Plant Management, Engineering & Operations … Management, Engineering & Operations Conference and Roundtable ... The presentation provides ... combined cycle gas turbine (CCGT) turndown

Austin EnergyAustin, TX

July 26-27, 2017

Plant Management, Engineering & Operations Conference and Roundtable

Instructed by:Elliot Hunt, Production Operations Engineer, Omaha Public Power District

Jon S. Cavote, President/COO, United Dynamics “AT” Corporation Kandi Forte, Director, Asset Management Services, Black & Veatch

Ed Seal, Director, Design Engineer & Projects, Arizona Public Service Mike Preston, Industrial Water Treating Section Leader, Black & Veatch

Michael Enger, Interim - Energy Market Manager, Austin Energy Craig Schaub, Control Engineering Manager, Austin Energy

Richard DIllon, Director, Market Policy, Southwest Power Pool Mike Ducker, Director, Market Analysis, Mitsubishi Hitachi Power Systems Americas, Inc.

John Wester, Energy Market Manager, Austin Energy Brian Foley, Director, Sales, PowerPhase

Edward Woods, Territory Sales Manager, Distributed LNG Solutions, Siemens

RMEL ~ 6855 S. Havana, Ste 430 ~ Centennial, CO 80112 ~ (303) 865-5544 ~ FAX: (303) 865-5548 ~ www.RMEL.org

Wednesday, July 26, 20178:00 a.m. – 9:00 a.m.Panel: Maintaining and Operating Equipment with Pending Shutdown in 5-10 yearsElliot Hunt, Omaha Public Power DistrictJon S Cavote, President/COO, United Dynamics “AT” CorporationKandi Forte, Director Asset Management Services, Black & Veatch

9:00 a.m. – 9:45 a.m.Workforce Management during the Uncertain Future of Coal Fired UnitsEd Seal, Director, Design Engineer & Projects, Arizona Public ServiceWill discuss real world scenario on the approach and actions taken at Cholla Power Plant when given direction and free rein to make the plant as cost ef-fective as possible, without compromising safety or environmental stewardship. Will discuss methodology used to achieve worker’s engagement, maintain leadership’s attention, and ultimately rethink daily op-erations given the reality of economic shutdowns. When a coal plant is no longer a base loaded unit, how is maintenance planned and executed, training of new personnel completed, opera-tor proficiency maintained.

9:45 a.m. - 10:00 a.m.Networking Break

10:00 a.m. - 10:45 a.m.ELG Compliance OptionsMike Preston, Industrial Water Treating Section Leader, Black & VeatchELG compliance has become an intense focus for many

coal fired power stations. The range of solutions has been expanding as utilities seek cost effective solutions. We will review a range of solutions and offer some high level cost expectations depending on the extent of treatment.

10:45 a.m. - 11:45 a.m.Austin Energy Generation Overview (Successes & Challenges)Michael Enger, Interim – Energy Market Manager, Austin EnergyThe presentation provides a brief history of the evolu-tion of the ERCOT market. Now a nodal market, the presentation looks into how the nodal market operates, including the settlement and scheduling of genera-tion and renewable assets as well as load. After the basic constructs of the nodal market have been outlined the presentation moves to an overview of Austin Energy’s generation assets and policy driven goals. The presentation will talk about successes in regards to moving towards achiev-ing those goals while also discussing the challenges of each generation type within the ERCOT nodal market and what tools/instruments are available to help address those challenges.

11:45 a.m. – 12:45 p.m.Networking Lunch

12:45 p.m. - 2:45 p.m.Roundtable (Starter Top-ics: Managing Workforce and Impact of Cycling Coal Plants)Roundtables offer a unique forum for peer-to-peer shar-ing of experiences, critical issues and expertise. The roundtable is a discussion group, open only to RMEL members. Discussion is

based on topics brought by attendees. Roundtables are focused on the open discus-sion period and provide each attendee the oppor-tunity for participation and dialogue on their particular issue. Roundtables are held in conjunction with a conference and many topics presented at the conference are discussed further in the roundtable setting. The roundtable is a good oppor-tunity to share experiences, troubleshoot problems and network with peers in a smaller, informal setting. Each participant is offered a chance to pose questions and share information. All attendees are encouraged to bring issues for discussion and materials for sharing.

3:00 p.m. - 4:00 p.m.Austin Energy’s System Control Center (SCC) TourCraig Schaub, Control Engineering Manager, Austin Energy This is a guided tour of Aus-tin Energy’s Control Center. From an observation room overlooking the Control Room, participants will be given a brief explanation of the System Controllers’ mis-sion and a description of the technologies applied. Austin Energy commissioned this control room in early 2013, employing state-of-the-art technologies.

Thursday, July 27, 20178:00 a.m. – 9:00 a.m.Panel: Operating Optimization of Plant for Energy Market you are In

Market Dispatch and Plant Optimization can be CoordinatedPanelist #1: Richard Dillon, Director, Market Policy,

CONFERENCE AgENdASouthwest Power PoolInputs to the market offer can help or hurt a genera-tor’s ability to operate op-timally. This discussion will increase awareness of how a market offer impacts the generator operations.

Economic and Operational Benefits of Improved CCGT TurndownPanelist #2: Mike Ducker, Director, Market Analysis, Mitsubishi Hitachi Power Systems Americas, Inc.Today’s utilities and markets are seeing an ever-increasing penetration of variable renewable energy resources. The existing grid system is being tasked with integrating these resources without jeopardizing reli-ability while still maintain-ing affordable electric rates. As a result, new and exist-ing dispatchable generation resources are considering technology improvements to further accommodate this market trend while maintaining their own positive operability outlook and financial health. One such improvement is the technology evolution of combined cycle gas turbine (CCGT) turndown. As new and existing resources are upgraded to improve their minimum emissions compliance load, positive outcomes are realized for both the individual plant as well as the grid system. At the plant level, these include lower O&M costs, decreased fuel costs, increased revenues and profitability, and increased operating hours. At the system level, these benefits include lower overall system costs, reduced emissions, and an improved outlook on the integration of vari-able energy resources. This presentation will seek to provide attendees with

Thank You RMEL Generation Committee

CHAIRJeff Karloff

Division Manager, Production Engineering & FuelsOmaha Public Power District

VICE CHAIRCurt Brown

Associate Vice President, Retrofit and Plant Betterment, Power Generation Services

Black & Veatch Corp.

David ArandaNewman Plant Manager

El Paso Electric Company

Ben CluffArizona Public ServiceEngineering Manager

Matt FergusonVP, Power & Energy Section Manager

HDR, Inc.

Richard ThreetDirector, Power Generation

PNM Resources

Kellen WaltersRegional Sales Director

Mitsubishi Hitachi Power Systems Americas, Inc.

John WesterDirector, Project and Asset Management, Power

ProductionAustin Energy

Tom WosRegulatory Program Administrator

Tri-State Generation and Transmission Assn.

The RMEL Generation Committee plans all RMEL Generation events. If you’d like to send

information to the committee, email James Sakamoto at [email protected].

updates on the key market changes influencing these CCGT flexibility improve-ments, an overview of the improvements, and how plant-level and system-level optimizations can realize the benefits of these new advancements.

Austin Energy Generation – Operating in the ERCOT MarketPanelist #3: John Wester, Director, Project and Asset Management, Power Production, Austin EnergyAustin Energy, a munici-pally owned electric utility, operates in the ERCOT nodal market. Even though Austin Energy has elected to remain a regulated and vertically integrated utility, the market design requires our generation assets to participate in the deregu-lated wholesale market. This presents a number of operational challenges which will be identified along with lessons learned to date and strategies we have employed to address these challenges.

9:00 a.m. – 9:45 a.m.Turbophase Dry Air Injection – Fast Ramp Power for Peak Power and Renewables FirmingBrian Foley, Director, Sales, PowerPhaseRenewable Energy Firming has become an increasing important issue as solar and wind generation continue to grow as part of the gen-eration portfolios across the United States. There are a number of compet-ing technologies that can provide this firming service, including reciprocating engines, small gas turbines and new technologies such as Turbophase.

This presentation will explore the pros/cons of various

renewable firming technolo-gies, looking at the financial and technical benefits for each choice. Case studies for ERCOT and PJM will be presented.

9:45 a.m. - 10:00 a.m.Networking Break

10:00 a.m. - 10:45 a.m.LNG Infrastructure – Distributed LiquefactionEdward Woods, Territory Sales Manager, Distributed LNG Solutions, Dresser-Rand Company, A Siemens BusinessThe point-of-use, micro-scale LNG production plant is a standardized product made up of packaged modules that work together to offer a decentralized, distributed approach to meet the growing demand for LNG supply. This presentation will cover the technology included with the LNGo micro liquefaction system, the distributed LNG value chain and how the distributed LNG model promote the growth of LNG as a clean fuel for multiple markets.

10:45 a.m. - NoonRoundtable (Starter Topic: Base Load to Peak Load)

Noon - 1:30 p.m.Grab & Go Lunch and Transportation to ERCOT Tour

1:30 p.m. - 4:00 p.m.ERCOT Tour(Including Transportation)

PLANT MANAGEMENT, ENGINEERING AND OPERATIONS CONFERENCE, ROUND TABLE AND PLANT TOUR

Meeting the Challenges of Market Transition

PANEL: Maintaining and Operating Equipment with Pending Shutdown in 5-10 years

Elliot Hunt Production Operations Engineer

Omaha Public Power District

Kandi Forte Director, Asset Management Services

Black & Veatch

Jon S. Cavote President/COO

United Dynamics “AT” Corporation


Elliot Hunt Production Operations Engineer

Omaha Public Power District

Maintaining High Reliability at Stations Nearing Retirement

Elliot HuntProduction Operations EngineerOmaha Public Power District

• Introduction to OPPD• OPPD’s reliability goal• Background on North Omaha Station• Action items to improve reliability• Results• Questions

Maintaining High Reliability at Stations Nearing Retirement

OPPD’s Reliability Goal• 90% equivalent availability factor (EAF) on

a three year rolling average basis• 4 Coal burning units.

– Nebraska City Station Units 1 & 2 with capacity of 1,347 MW

– North Omaha Station Units 4 & 5 with capacity of 317 MW / 557 MW

• Five PRB coal burning steam generators built from 1954 -1968

• Coal burning capabilities were decommissioned for Unit 1, 2, and 3 in 2016

• Unit 4 and 5 slated to convert to natural gas in 2023• OPPD still depends on North Omaha Station (NOS) for

capacity and high reliability.

North Omaha Station

June 17, 2017

• North Omaha served for many years as OPPD’s main baseload generator and in recent years has shifted to a more flexible load follower.

• This has required adapting to allow:– Lower loads– Higher loads on AGC– Increased reserve shutdowns

• Simultaneously the plant undergoes:– Decreasing staff– Pressure on maintenance budget– Additional emissions equipment and

consumables • All of these changes challenge plant

reliability.

• Formed team responsible for progress towards EAF goal.• Employee reliability mentality • Condition based maintenance• Detailed outage scheduling analysis• Encourage out of the box problem solving• Implement economically justified projects• Adopt new lean methodologies• Plan around known bad actors• Always keep safety a priority

Actions

• Comprised of div. managers, plant managers, maintenance superintendents, engineering, and energy marketing.

• Tasked with meeting corporate EAF goal.• Reviews all events to confirm follow-up action plan and owner.• Focused on reliability rather than maintenance.• Discusses current or future risks.• Evaluates need or benefit from outside help.• Increases information flow between plants.• Developed and updates Reliability Dashboard and

Top 10 Lists

Formed GREAT(Generation Reliability Evaluation and Analysis Team)

• Goal: Energy production employees aware of EAF target and their ability to move the needle.

• Ways to increase employee focus on reliability.– Post Dashboard and Top 10 Lists– Monthly review of top 10 lists– Demonstrate importance by steady progress on

reliability impacting projects.– Share lost opportunity costs.

Employee Mentality

• Transition to condition based maintenance is not new at NOS.

• Pressure on O&M budget has pushed NOS to fully adopt CBM strategy.

• Examples:– Unit 4 condensate pump– 2017 mini outage scope

Condition Based Maintenance

Outage Scheduling and Planning• Historically:

– Standard outage frequency – Minimizing outage duration– Maximizing PM completion rate

• Recent changes:– NOS revisits duration evaluation as outage approaches using expected value of lost generation,

overtime cost, and scope.– In some cases this may increase EAF but is economical for the station.– Allocating resources sparingly

• Current effort to evaluate outage schedule involves:– Bottom up review - all outage work orders and PM’s evaluated to determine optimal frequency– Top down review -

• Possible schedules are evaluated with major outage jobs included• This method attempts to lengthen outage frequency and improve EAF

Outage Schedule Spreadsheet

Out of the Box Problem Solving• Magnetic drives

– Some drives replaced years ago but cannot justify replacement of remaining drives– Overhaul task review– Lock nut repairs

• Mill hydraulics– Frequent leaks and lengthy troubleshooting process – New valves installed to speed troubleshooting process

• Boiler feed pump fluid drive– Identified vibration that poses risk to 50% of unit load. – Purchasing refurbished rotating element

• Primary air fan repairs and balancing– Unit 5 was available to run at ~2/3 load after temporary duct blank installed while repair

work completed on fan wheel and housing

Out of the Box Problem Solving• Balancing act • Something between full replacement /

rebuild and:

Justify New Projects• NOS installed vibration monitoring system on

critical plant equipment in 2016. – Basic continuous vibration monitoring on 35

machine trains.– Allowed for better CBM information and led to

more informed decisions.– Improved machine protection – Station has already benefitted from timely shut

down of operating machines.

Justify New Projects• Online blowout method for Unit 4 magnetic drives.

– Compressed air routed to each side of 6 remaining regular service magnetic drives

– Regular frequency blowdown of magnetic drive to reduce dust build-up

• Mill table seals– Unit 5 mills have long term problem with mill table

seals– New style of table seal is in trial and will replace old

style completely if satisfactory

Adopt New initiatives• OPPD 2017 Lean Fossil effort introduced new

methodologies• Idea Generation Sessions(IGS), Swarm

meetings• Root cause analysis

• craft involvement• standard procedure• verify results

Plan Around Bad Actors• As retirement horizon approaches, more problem

areas will be identified that cannot be eliminated.• Develop plans to mitigate the outages or derates

caused by identified area. – Unit 4 throttle pressure reduced by ~20% to prevent

low temp super heater boiler tube leaks• No MW impact at normal operating load

– Nebraska City Unit 1 slope tube leaks• Long term struggle to reduce slag fall but have

developed methods to repair leaks quickly

Results• Unit 4

– 7 year average EAF 88.1%– 7 year average EFOR 5.9%

• Unit 5– 7 year average EAF 79.7%– 7 year average EFOR 14.8%


Jon Cavote President/COO

United Dynamics Corporation

The Name Behind The Flame

“Begin With a Plan, Execute , End with Resolve”

Jon S Cavote

2681 Coral Ridge Road

Brooks, KY 40109

502.957.7525 Tel

502.957.5441 Fax

Serving the Power Industry Since 1979

United Dynamics AT Corporation

“Commonalities between utilities facing unit shut down

and gas conversion.”

The key is to focus on recommendations that will improve existing coal-fired power plants' reliability and availability to eliminate or reduce forced outages and extend the time between planned maintenance outages. Achieving this goal, understanding an upcoming shut down or off line date being immanent is the common challenge for many utilities across the country.

"Do More with Less" corporate environments.

Maintenance projects are typically driven by unrealistic time constraints and typically delivered late.

Data, and the trends found & realized within data, paint a vital picture. Decisions on pressure part component repairs are varying based on future unit shut down projections.

A Risk Driven Project contains all the planning elements of traditional planning approaches, a focus on detailed analysis of risk events and classification of risk events as critical risks events or non-critical risk events. Instead of the work flow or logic of a project considering only time and resource constraints, the Risk Driven Project highlights the highest priority events and utilizes a pre conceived plan to monitor and control these critical risk events

Once projects are selected and planning is ready to start, key Risk Driven Project objectives are:

Establishment of Unacceptable and Acceptable Project priority constraints by senior management based on remainder of time before shutdown vs. no shutdown.

Consideration of inspection risk events, chains of risk events and risk responses in structuring the planning, execution, control & evaluation, and termination of repair items based on criteria.

The key difference between the two approaches is that the:

Value-based approach involves strategic decision-making that takes the long term affect of repairs into account when making replace, repair, and overhaul, retrofit, and refurbish decisions.

Cost-based approach relies on available budget (can we afford it?) for maintenance decision-making that often ignores equipment thermal performance considerations. Cost based decisions are being made considering factors that include; duration of operating time before shut down, risk of failure reoccurrence before shut down, and repairs considered based on failure risks after a unit fuel change.

Gather data Determine goals based on budget,

time frame, and shut down or gas conversion dates.

Establish schedule requirements and constraints

Establish an outage tracking system to track daily progress

Work together on outage scope development

Hold routine meetings throughout overhaul attended by outage management, inspection, QAQC, scaffolding, and Craft foreman.

Track daily progress on scope items and completion.

Identify all completed work

Compare work with projected work from scope

Make adjustments agreed upon between plant personnel and craft firm

Develop working list of repair items not completed. You never know what changes may occur.

Questions!!

Thank You

2681 Coral Ridge Road

Brooks, KY 40109

502.957.7525 Tel

502.957.5441 Fax

Serving the Power Industry Since 1979

United Dynamics AT Corporation


Kandi Forte Director, Asset Management Services

Black & Veatch

Workforce Management during the Uncertain Future of Coal Fired

Units

Ed Seal Director, Design Engineer & Projects

Arizona Public Service

Workforce Management during the Uncertain Future of Coal Fired Units

Ed SealDirector, Design Engineer & ProjectsArizona Public Service

Goal: Create a New Cholla

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Problem statement:How to man and operate Cholla as a three unit, peaking coal plant, with one unit online for voltage control?- This was modified to three unit peaking coal plant October-May,

base loaded (at reduced load) for summer run (June-September),with one unit online for voltage control.

Old Cholla:• 4 coal fired units, built 1961 – 1978

• One unit decommissioned in Oct 2015, decom activities into Spring 2016 (air gap vice removal)

• One unit wholly owned by Pacific Corporation• Base loaded 24/7• Coal delivered by rail• Located northern Arizona – Joseph City, AZ• Union workforce – Operations and Maintenance• Three Control Rooms• Maintenance Modifications Contractor (MMC) support

Method• Formed small group, consisting of all Managers (Production,

Operations, Maintenance, Planning, Engineering) and select forward thinkers. Total team of 13, including two Union Stewards.

• Initial meeting was to brainstorm items to further investigate.• Grouped items into areas

– Training and Manning– PMs and work actually being done– Supply Chain– Outside Services– Long range planning, LRF– Plant Operating characteristics

• List socialized with Plant personnel via Managers/Supervisors.• Assigned areas to team members, tasked with discussing ideas

with their team and returning with suggested action items.• Developed action items within each area (over 50 total

initially)• Weekly meetings for first month, 2-3 hours per meeting

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Sample actions

Review of top ten material conditions

Top 10 Material Conditions may not all be issues that Cholla needs to support based on being a peaking instead of base load running plant.

Evaluate material condition list and determine if the issues are long term issues or short term issues and if Cholla needs to do to support the plant for time we will run.

ALREADY Reviewed by Maintenance Supervisors & Engineering

We need to get the right corrective maintenance work orders in the schedules, too often WO's are sent from CAR Screening to Engineering or Planning that are nice to do work.

ACTION: Institute better screening of pri. 4 WO's to determine nice to do vs need to do instead of sending WO on to ENG and/or Planning. This review should be outside of CAR SCRG MTG, review WO's from week prior. CompleteACTION:Set meeting notice for review of last 7 days of WO's to determine the following: EI, Mech, hrs, description, Need/Want/Question. Attendance: Planners, WWC, Maint. Sup, SS's CompleteACTION:Set expectations SS Reviews Complete

CHQ costs to Cholla(FTEs)There is a CH cost associated with corporate affiliated positions that needs to be evaluated to determine potential way to save.

Action: Determine cost for CHQ (CFAL's support, 2016 new job plan initiative w/ contractor, etc..) to determine if changes can be made to support Cholla savings (I.E. travel to Cholla vs audio/visual, engaging CH employees to perform assessments/audits, allowing CH to maintain Job plan development static, etc…).

Plant Manager to request information

Note: The 2016 initiative to change fleet job plans to a standardized method will cause CH to change all current Job plan's as CH built tasks in Maximo long ago that support job plan development.

Knowledge transfer of Gas and Oil Plants

Gas and Oil plants have knowledge pertaining to how the G/O plants ran to support peaking plant operation effectively that needs to be shared with CH. Benchmarking needed to ensure knowledge transfer.

Benchmark G/O plants to determine how they were sucessful in being peaking plants (Operations, Maintenance, Planning, Engineeering) 4

Manning dynamics

• Retirement (near term)– Operations = 2, including one Shift Supervisor (SS)– Maintenance = 3– Planning = 1

• Transferring (immediate)– Operations = 2

• Flight risk (estimates)– Operations = 3, including one SS– Maintenance = 3

• CO requirement will reduce by five once U1 Control room relocated

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Workforce utilization

• Operations utilization when one unit operating– Training (Fire Brigade, cycle, OJT, Control Operator

intensive include on simulator) – Housekeeping– Support Supply Chain in the warehouse when needed – Augment maintenance crews during outages and scheduled

work weeks – Back shift manning: 1 SS, 2 COs, 4 AOs, 2 MOS, 2 UEOs

• Maintenance on Shift (MOS) include E&I (1) and Mechanic (1)– Will use AOs as Helpers– Will cross qualify in an Ops area to cover if needed

• Equipment overhauls (Mills, crushers, etc) and outages worked on Straight time basis

• Numerous personnel loaned throughout the Fleet

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Operations activities (April/May)

• Two weeks of specific systems and operating board training for ALL CO’s. This will also complete a majority of OJT training requirements.

• Cycle training 3-8 will be conducted on straight time for operations.

• Fire brigade training requirements completed through August/Sept will also be completed on straight time

• Plant wash down (including boilers).• Maintenance support from Operations and UEO’s (coal

handling).• UEO’s working with maintenance will be completing

qual card components during this time.• On-shift activities include running equipment checks,

fire watch, combustible dust reports, monthly fire extinguisher inspections and backlog reduction (hours apply to OJT).

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Operations

• Current structure:– 12 SS’s – 19 CO’s– 44 AO’s– 14 UEO’s– 1 Manager+1 Administrator– Total - 91

2016 Navigant number for operations is 91. Currently at 81 (10 Vacancies).

• Proposed – 11- SS’s (2 per crew, LOTO, Relief, Days)– 19*- CO’s (will reduce to 14 once U1 Control

room moved to U3)– 38 - AO’s– 11- UEO’s (2 per Ops crew, 3 in relief)– 1 Manager + 1 Administrator– Total - 76

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Maintenance

• Current structure:– 6 Supervisors – 26- E&I– 22- Mechanics– 9- Machinists– 15- Welders– 1 Manager+1 Administrator– Total - 80

2016 Navigant number for Maintenance is 80. Currently at 74 (6 Vacancies).

• Proposed – 5- Supervisors– 24- E&I– 21- Mechanic– 9- Machinist– 14- Welders– 1 Manager + 1 Administrator– Total - 75– Supervisor, 4 E&I, 2 Machinist, 6 Mech/Welder

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Planning

• Current structure:– 7- Online Planners– 3- Outage Planners– 2- Work Week Coordinator (WWC)– 2 Ops Support Group– 1- Vendor Liaison– 1 Manager+1 Administrator– Total - 17

2016 Navigant number for Planning is 17. Currently at 15 (2 Vacancies).

• Proposed – 6 - Planners– 2 - WWC– 1- Outage Scheduler – 2 - Supervisors– 1 - Vendor Liaison– 1 Manager + 1 Administrator– Total - 14

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Matrix, others

• Matrix folks • Engineering at Cholla – reduced by one • Training – reduced by 0.5 • Supply Chain at Cholla – reduced by two

• Billets not being pursued: Assistant Operations Mgr, Operations Technical Advisor, Planning Supervisor.

• Still under evaluation: Production Mgr, Administrative Assistants, sharing of Fire Chief with Four Corners

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Coal Pile

• Current coal pile status is 907K tons (89 days)• Target for coal pile storage is 1.15M tons but has been

as high as 1.2M tons. • Initial engineering reviews show could stack

approximately 127K tons north railroad tracks• Environmental considerations

• Storm water pollution prevention plan update• Aquifer Protection Plan update• Particulate matter

• Soil preparation• Grading and compaction of top 8” of soil • $165K

• Retention pond capacity evaluation

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Contractor Plan

• Reduced Brand, Riley, CB&I footprint. New expected O&M FTE = 25, down from 38. • CB&I (MMC) - 17• Riley Industrial - 7• BRAND (scaffold)- 5• Estimated savings of $1,129K [$550K (CB&I,

22%), $329K (Riley, 31%) $250K(BRAND), 25%)]

• All 2016 PO’s were reviewed for reduction to the CWP.

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Progress report at 60 days

• Reduced the Cholla organization to 176 direct report to Plant Mgr.

• Reduced the number of matrix personnel, specifically Supply Chain, training and Plant Engineering. Initial cuts were taken, but in reality it is a process of continuous evaluation.

• Reduced cost of U1 outage, worked nearly entirely on days.• Deferred U3 major outage to Spring 2017, will accomplish a

limited scope outage in April-May 2016, working days only. • Changed the Ops crew manning for single Unit operations.

Remaining Ops crew personnel are attending training or working with Maintenance dept.

• Reviewed all Special Maintenance Project budgets for 2016, total savings $1,034K. Reduction generated based on new anticipated run hours and historical spend to accomplish projects. (U1-$110K, 17%), (U3-$195K, 12%), (U4-$369K, 17%), (Common-$359K, 17%).

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Progress (cont)• Commenced project to combine U1 control room into existing

U3 control room. Project is managed by Cholla Engineers, may be able to complete prior to summer run.

• Negotiated with the Union to allow MOS to be trained and qualified 1 or 2 Operations areas (General water + ?), will allow MOS to cover Ops crew unscheduled PTO.

• Negotiated with IBEW to have UEO as flaggable position, effective first pay period in April 2016.

• Reduced BRAND, Riley Industrial, CB&I footprint. • Complete review of remaining 2016 PO’s, reduced estimated

spend: $549,500 (3%)

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Progress (cont)• Scheduled all Ops crew training for cycles 3-8 to be

accomplished prior to June 01, which is start of summer run and expected three unit operations.

• Fully manned the relief crew, allowing reduction in need for OT.• Reinstated mechanical MOS, minimizing the need to call out for

Pri 1-2 work. Expect additional benefit in reduction of CM back log.

• Increased utilization of AO secondary skill to assist with Maintenance work – both with MOS and assigned maintenance crew.

• Loaned several folks – Ops, Maintenance and Engineering - to other Plants within Fossil. {Turbine expert to 4C since early January, four to Redhawk (10 days), two to Ocotillo (6 weeks), four to 4C (6 weeks), Boiler Engineer to Saguaro (3 weeks), two to West Phoenix (2 weeks)}

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Significant initiatives still in progress• Review and reduce Capital Projects based on new run

profile: U1 , U3, U4, Common• Review and reduce Corrective Maintenance back log based

on expected lifetime: U1, U3, U4, Common, Coal• Review Planned Maintenance, eliminating duplicates. • Changed PM scheduling to base on run time vice calendar

days, able to accomplish this due to adding counters. PM reduction based on new run time:

• Review of DCPs, to work only Safety, Environmental, and those tied to Cholla Top Ten Material Issue.

• Consolidating to one manned warehouse vice two; modifying materials handling processes.

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Measuring effectiveness

• Do we keep our worker injury rate near zero? • Do we not have REI’s nor environmental near misses? • Do we meet our generation commitments?• Are we at or below our new budget (Current Work Plan)?• FTE Contractor O&M headcount will be at or below new

target• Does the CM back log go down each month? • Does our PM completion rate remain >/= 90%? • Does our Priority break in #s go down? # of Maintenance

qual cards completed by Operations?• # of Maintenance personnel qualified in Operations areas?

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Comments

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ELG Compliance Options

Mike Preston Industrial Water Treating Section Leader

Black & Veatch

7/24/2017

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ELG COMPLIANCE OPTIONS

Mike Preston, P.E.INDUSTRIAL WATER TREATING SECTION [email protected]

26 July 2017

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ELG Overview

Solutions

Treatment Technologies

Estimated Costs

AGENDA

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ELG Overview

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Black & Veatch

Impacted Wastewater Streams

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FGD Wastewater

Fly Ash Transport

Bottom Ash Transport

Landfill Leachate

Flue Gas Mercury Control Wastewater

Gasification Plants

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Waste Stream Existing PlantsAvg / Max

FGD Wastewater

As - 8 / 11 ppbHg - 356 / 788 pptNO3/NO2 - 4.4 / 17 ppmSe - 12 / 23 ppb

Ash Transport No Discharge

LeachateImpoundmentTSS - 30 / 100 ppmOil & Grease - 15 / 20 ppm

Non-Chemical Metal Cleaning No New Limits

New ELG Limits – Surface Discharge

Black & Veatch5

These are minimum requirements; states can apply stricter limits

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Anti Circumvention Provision (ACP)

• Requires a particular waste stream for which a zero discharge limitation has been established not be used in another plant process that results in a surface water discharge. The exception to this provision is use of ash transport water as FGD makeup water.

Legacy Provisions

• Ash transport water generated prior to the date established by the ELG as the control date (earliest Nov 2018; latest Dec 2023) would be treated under current BPT (settling ponds).

Combined Waste Streams

• Factored approach to limits where waste streams of different categories are combined for discharge.

Black & Veatch

Additional Provisions

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7Black & Veatch

Recent EPA Decisions May Affect Schedule, Or May Not

EFFLUENT LIMITATION GUIDELINES TIMELINEEFFLUENT LIMITATION GUIDELINES TIMELINE

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Coal Combustion Residuals (CCR)• Regulates disposal of

coal ash & FGD byproducts

• Requirements for landfills and surface impoundments

• Liner, leachate collection & groundwater monitoring

ELG• Plants may have FGD

wastewater sent to onsite ponds

• Ponds typically closing due to CCR rules

• Segregation of other wastewater streams sent to ponds is required

Black & Veatch

Overlap of EPA Regulations

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9Black & Veatch

CCR ELG Intersection

CCR Impoundment

(Pond)

Ash Handling Systems

Low volume wastewater

FGD wastewater

Metal cleaning wastewater

Other wastewater

Coal pile runoff

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SOLUTIONS

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Low Volume Wastewater (LVW)

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Black & Veatch12

Challenges

• Considering future regulatory changes

• Cataloging all the flows

• Understanding plant water balance

• Data collection and analysis

• Flexibility

• Understand variable water quality

• Sizing treatment systems

• Solids handling

• Oily water

• Schedule

• Coordination with ash system modifications

• Permitting

7/24/2017

13

Black & Veatch

Ash System Solutions

Replace non-compliant

impoundment with compliant

impoundment

Replace non-compliant

impoundment with compliant

impoundment

Dewatering Bin SystemDewatering Bin System

Dewatering Basins System

Dewatering Basins System

Submerged Scraper Conveyor

Submerged Scraper Conveyor

Dry Ash Conveyor System

Dry Ash Conveyor System

Remote Submerged Scraper Conveyor

Remote Submerged Scraper Conveyor

7/24/2017

14

Flue Gas Desulfurization (FGD) Wastewater

Waste stream typically blown down from gypsum dewatering system

Wet absorber bleed stream

Dependent on type of coal

Controls FGD chemistry

Black & Veatch14

7/24/2017

15

Parameter Range

Total dissolved solids (mg/L) 5,000 to 40,000+

Suspended solids (mg/L) 5,000 to 30,000+

Chlorides (mg/L) 1,000 to 30,000+

Arsenic (μg/L) 10 to 3,000

Mercury (μg/L) 6 to 1,000

Nitrate/Nitrite as N (mg/L) 1 to 50

Selenium (μg/L) 100 – 5,000

FGD WW Quality

Black & Veatch15

• Materials of construction limit chloride concentration

• Dewatering system, coal, chloride limits and unit load impact chemistry

7/24/2017

16

• Emphasis on water reduction to minimize FGD wastewater stream

• Segregating non-FGD wastewater

• Requires changing operational mindset

• Importance of water quality data

Water Management

Black & Veatch

Every 1 gpm of FGD wastewater discharge may cost as much as $90,000+ to comply with regulations

16

7/24/2017

17

TREATMENT TECHNOLOGIES

17

7/24/2017

18

18

Treatment & Discharge• Lower cost• Future regulation changes• Delayed performance

feedback

Zero Liquid Discharge (ZLD)• Higher Cost• Delayed compliance date• Reusable water stream

The treatment flowrate impacts feasibility of options

Two Treatment Approaches…

Courtesy GE

7/24/2017

19

19

Physical/Chemical Precipitation

Biological Treatment

Packed bed (GE ABMet®)

Fluidized bed (Frontier, Envirogen)

Zero Valent Iron Pironox®

(Evoqua)

Treatment & Discharge Technologies

7/24/2017

20

Black & Veatch

Physical/Chemical Treatment

20

Goal

TSS ReductionHeavy Metals Reduction

(As & Hg)

Equipment

Reaction tanks, clarifiers, dewatering,

chemical feeds

Considerations

Solids handling, filtration, lime

softening

Does not remove nitrate/nitrite and selenate (SeO42-)

7/24/2017

21

• Anaerobic attached growth bioreactors

• Utilize activated carbon media for microbes

Biological Treatment

Black & Veatch

Nitrate/Nitrite

• Denitrification in 1st

Stage to nitrogen gas

Selenium

• ORP controlled to target selenium removal

OR

P

0 mVO2

NO3

NO2

SeO4

SeO3

SO4

-100 mV

-50 mV

-150 mV

-200 mV

21

7/24/2017

22

22

GE ABMet®

• Packed bed• No downstream

filtration• Largest footprint• ~8 hrs contact

time

• Packed bed• No downstream

filtration• Largest footprint• ~8 hrs contact

time

Envirogen

• Fluidized bed• Downstream

filtration• Smallest footprint• ~1 hr contact time

• Fluidized bed• Downstream

filtration• Smallest footprint• ~1 hr contact time

Frontier SeHAWK®

• Fluidized/packed bed

• Downstream filtration

• Medium footprint• ~ 4 hrs contact

time

• Fluidized/packed bed

• Downstream filtration

• Medium footprint• ~ 4 hrs contact

time

Black & Veatch

Contact time dependent on nitrate and selenium loading

Biological Treatment Technologies

7/24/2017

23

Eq & Rxn Tanks Clarifiers Sand Filters Bioreactors

DischargeFGD

Wastewater

Recovery Sump

Biological Treatment Flow Diagram (Envirogen/Frontier)

Sludge Tank Filter Press Solids Disposal

Ultrafilters

23

7/24/2017

24

• Zero valent iron (ZVI) media to reduce selenium, nitrate/nitrite and other heavy metals

• Reagent (ferrous chloride) fed to prevent rust formation on the media

• Upstream filtration not required

• Quick startups (not biological)

Zero Valent Iron (Pironox®)

Black & Veatch

Requires downstream clarification, thickening and filtration

24

Fe0

Fe0

Fe0

Fe0

Fe0

Fe0

7/24/2017

25

25

Brine DisposalVolume ReductionPretreatment

Physical/Chemical Precipitation

Spray Dryer

Membrane Treatment Crystallizer

Thermal Evaporation Stabilization

ZLD Technologies

7/24/2017

26

26

Reverse Osmosis

High pressure pumps push water

Varying recovery

Waste recycle/ batch operation

Forward Osmosis

Draw solution pulls water

80-90% recovery

Thermal draw solution recovery

Black & Veatch

Membrane treatment requires extensive pretreatment and additional treatment for brine stream produced

Membrane Treatment

7/24/2017

27

• High recovery rate (80-90%)

• High energy; 80-90 kWh/kgal

• TDS: 200,000 – 300,000 ppm

• Brine stream requires treatment

• Pretreatment requirements dependent upon brine disposal method

Source: General Electric

Thermal Evaporation – Thin film evaporators

Black & Veatch27

7/24/2017

28

28

Purestream evaporator• Thermal core containing recompressed vapor• Submerged in brine solution• Simplify cleaning

Heartland LM-HT® Concentrator• Requires a fuel source or hot gas stream (600-800F)• Wastewater and hot gas mixed in high turbulent zone• No water recovery; concentrated brine stream

Black & Veatch

Both technologies eliminate heat exchangers within evaporator

Other evaporation technologies…

7/24/2017

29

Black & Veatch

Brine Disposal Options

29

Crystallizer

• Expensive materials• High energy• Difficult

pretreatment

Fly Ash Disposal

• Limited flow rate• Material upgrades• Impact to fly ash

sale

Blending

• Pozzolanic Solidification• Fly ash and reagent• Requires bench scale

testing

7/24/2017

30

• Fully evaporate wastewater, leaving only crystals

• Evaporated water is not recovered

• Old technology, new application

• No pretreatment; carbon steel vessel

• 0.5 – 1% heat rate impact

• Flow rate limited by flue gas temperature, pressure drop, and flue gas volume

Spray Dryer

Black & Veatch

Need to evaluate additional solids loading and impact to fly ash quality

30

7/24/2017

31

31Black & Veatch

Spray Dryer – Flow Diagram

7/24/2017

32

ESTIMATED COST

32

7/24/2017

33

• Spring 2016 study

• Two units

• Original flow rate – 275 gpm

• Revised flow rate – 50 gpm

• No existing physical/chemical system

• Comparison of 5 treatment options

Recent ELG Project

33

7/24/2017

34

Phys/Chem +Bio

BC / CrysSpray Dryer

BC / Solid

Footprint, ft2 17,200 14,750 8,800 16,000

Power (kW) 160 2000 1930* 1890

Installations? Several Few Two ?

NotesBoth ABMet

and EnvirogenSteam available for crystallizer

One spray dryer for each

unit

Required an additional reagent

Treatment Options – 275 gpm

Black & Veatch34

*The large power requirements includes heat rate impact

7/24/2017

35

Black & Veatch35

$9.6M

$7.2M

$12.2M

$18.5M

$10.6M

$5.5M $5.0M

$8.6M$7.1M

$8.1M

ABMet Envirogen BC/Cryst Spray Dryer BC/Solid

Major Equipment Costs275 gpm50 gpm

7/24/2017

36

Black & Veatch36

$41.4M

$31.9M

$51.9M

$81.4M

$46.0M

$25.3M $23.3M

$37.2M$31.2M

$36.3M


Total Installed Costs275 gpm50 gpm

7/24/2017

37

Black & Veatch37

$1.0M $0.8M

$3.6M

$5.9M

$2.4M

$0.6M $0.6M

$1.6M$1.2M $1.1M


Annual O&M Costs275 gpm50 gpm

7/24/2017

38

Other Cost Considerations

Each plant is unique and all aspects need to be taken into account for ELG compliance

ELG and CCR impacts

Segregation of wastes

Schedule

Existing Equipment

Pilot Costs

Black & Veatch38

7/24/2017

39

• Water Management Review

• Solutions Evaluation

• Treatment Approach

• Schedule and impact from other rules

• Piloting

Summary

Black & Veatch39

Austin Energy Generation Overview (Successes & Challenges)

Michael Enger Interim – Energy Market Manager

Austin Energy

Austin Energy Generation Overview –Success & Challenges

Michael EngerInterim – Energy Market Manager, Market Operations & Risk Management

www.austinenergy.com

ERCOT Service Territory

2


Overview of the Evolution of ERCOT

Around the start of WWII, several electric utilities in Texas agreed to operate together as the Texas Interconnected System (TIS) to support war effort

Members recognized reliability advantages of interconnection and continued to operate and develop interconnected gridERCOT formed in 1970 to comply with NERC requirements (not reliability)Control Areas managed reliability Generation served load within control area Production cost drove cost to serve load

1995 Legislation passed to deregulate wholesale electric marketsTexas still had 10 control areas, but generation could be bought or sold to help serve load or maximize generator revenueGeneration still served load in control areas but now augmented with some purchases and sales

3


Overview of the Evolution of ERCOT

1999 SB7 passed to lead to deregulation of retail load in TexasUnbundled investor-owned utilities Assigned ERCOT 4 primary responsibilities

− System reliability− Open access to transmission− Retail switching process for customer choice− Wholesale market settlement for electricity production and delivery

2001, the 10 existing control areas in Texas were consolidate into a single control area administered by ERCOT (ISO)

Zonal Market structureWholesale power sales now subject to centralized power schedulingCentralization of ancillary services to ensure reliability

In 2003, PUCT orders development of a wholesale nodal market designDecember 2010, ERCOT Nodal Market goes live

All load is purchased from ERCOTAll generation is sold to ERCOT 4


• Generation Dispatch • Security Constrained

Economic Dispatch (SCED)• Resource specific offers • Resource specific dispatch

• Goal• Balance generation & demand• Manage congestion

• Energy Pricing• Locational marginal price for

energy (LMP)• > 8,000 nodes (electrical

buses)• 500 Settlement Point Prices

(SPP)

ERCOT Nodal Market

5


• Generation output must meet system demand to maintain frequency at 60 Hz

• ERCOT must ensure sufficient capacity is online to meet forecasted demand

• ERCOT uses DRUC and HRUC to procure additional capacity

• Insufficient capacity can result in emergency action

• Energy Emergency AlertsEEA 1: PRC < 2,300 MW

• All available units, DC import, ERS 30

EEA 2: PRC < 1,750 MW• ERS 10 & 30, interruptible I&C load

EEA 3: PRC continues to trend down or frequency < 59.8

• Load shed

Capacity vs Energy

6


Day Ahead and Operating Period Timeline

7

Source: ERCOT


• Day Ahead Energy Market• Voluntary and financially

settled• Hedges real time price

risk • Settles hourly

• Day Ahead Ancillary Services Market

• Physically binding

• Real Time Energy Market• Dispatches every 5

minutes• Settles every 15 minutes• Can exhibit periods of

high volatility• $9,000 market price cap

ERCOT Facilitated Markets

8


• Exchange Traded• Intercontinental Exchange• Nodal Exchange• NYMEX (CME)

• Broker Facilitated• IVG• ICAP• Amerex

• OTC (Over the Counter) Direct• REPs• Gen Cos• Energy Trading Companies• Banks• Speculators / Proprietary

Traders

Bilateral ERCOT Markets

9Timeframe can vary from next hour to next 30 years


$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

Load Zone South ERCOT 15 minute RT SPP –June 18th through June 20th, 2017

10

$/MW


Load Zone Austin ERCOT 15 minute RT SPP –Cal 16

11-$200

$0

$200

$400

$600

$800

$1,000

$1,200

$1,400

$1,600

174

214

8322

2429

6537

0644

4751

8859

2966

7074

1181

5288

9396

3410

375

1111

611

857

1259

813

339

1408

014

821

1556

216

303

1704

417

785

1852

619

267

2000

820

749

2149

022

231

2297

223

713

2445

425

195

2593

626

677

2741

828

159

2890

029

641

3038

231

123

3186

432

605

3334

6

$/M

W


ERCOT Generation Supply Curve - 2016

12Source: SNL


Austin Energy

13


Austin Energy

14

Non-Opt in Municipally owned Electric UtilityLocally owned and operated since 1895Transfer approximately $105M annually to the City’s general fund7th Largest Public Power Company - customers

The Austin City Council serves as the utility’s board of directors55% renewable energy goal by 2025Reduce carbon dioxide (CO2) power plant emissions 20% below 2005 levels by 2020900 MW energy efficiency and demand response savings by 2025Affordability goal to keep rates below 2% annual increase and remain in the lowest 50th percentile for retail rates in Texas

Our customers help shape our strategic goals and overall utility styleThrough the officials they electStakeholder process


Austin Energy – Diverse Generation Mix

15

Generation Type Total Capacity

Natural Gas – Steam 730 MWs

Natural Gas – Combine Cycle 300 MWs

Natural Gas – GTs 470 MWs

Natural Gas – DG 5 MWs

Coal 600 MWs

Nuclear 400 MWs

Wind 1,253 MWs (additional 200 MWs under contract)

Solar – Utility Scale 316 MWs (additional 320 MWs under contract)

Solar – DG 45 MWs (approximately)

Biomass – Waste Wood 100 MWs

Biomass – LFG 8.5 MWs


Austin Energy – Generation Asset Map

16

Roserock Solar


Austin Energy - Challenges

17

ERCOT Nodal Market structure and generation mix currently rewards flexibility and can be unforgiving for baseload generation

Lack of the ability to cycle puts economic pressure less flexible generationDAM does not work well to economically dispatch units with longer start-up times

Austin Energy’s high renewable goal and climate goal is moving generation portfolio away from controllable resources and towards more intermittent resources

Increases the challenge in providing stable rates to our customersIncreases forecast risk when hedging further out in the futureIncreased congestion exposure due to location of assets relative to load


Austin Energy - Successes

18

Increased use of forward power markets to increase economic benefit for aging, less efficient assets

Increased net revenue by > 50% over the past 2 years on older natural gas steam assetsIncreased net revenue by hedging downside price risk for baseload units in OffPeak periods

Operational changes at plants to increase flexibilityLower LSLsAdditional cycling


Austin Energy - Successes

19

Successfully negotiated some of the lowest cost renewable PPAs to date

“World’s Cheapest Solar Power Lands in Austin, Texas” –cleantechnica.com (2015)“Austin Energy gets record low solar bids under 4 cents/kWh” –utilitydive.com (2015)“World’s Cheapest Solar Power Deal in Austin, Texas” – costofsolar.com (2014)

Continue to improve renewable portfolio Locational diversityTechnology diversityComplimenting generation output curves

Continue to evaluate technologies viability in the evolving market

Quick start unitsBattery storage


Questions

20

?

Austin Energy’s System Control Center (SCC) Tour

Craig Schaub Control Engineering Manager

Austin Energy

PANEL: Operating Optimization of Plant

for Energy Market you are in

Richard Dillon Director, Market Policy Southwest Power Pool

Mike Ducker

Director, Market Analysis Mitsubishi Hitachi Power Systems Americas, Inc.

John Wester

Energy Market Manager Austin Energy



Richard Dillon Director, Market Policy Southwest Power Pool

Market Dispatch and Plant Optimization can be CoordinatedRichard DillonSouthwest Power [email protected]

2

Many actions you do to “protect” yourself actually hurt!• What is a market offer?

• “Control my destiny”

• “Shoot myself in the foot”

• “Stop doing that!”

3

What is a market offer?• Operational Parameters Minimum/Maximum MW Ramp Rate Start-up/Minimum Run Time Available/Shutdown Minimum Time Between Startup

• Financial Parameters Energy Offer Operating Reserves Offer (Regulation &

Contingency) Startup & No-Load Offer

4

I know how this plant operates best and want to “control my destiny”!• Self-commit Long startup time Long minimum run time Long minimum time between startup

• Self-dispatch High Minimum MW/Low Maximum MW Low Ramp Rates

• High/low financial offers

5

Why am I being yelled at for “shooting myself in the foot”?• Unable to get revenue Long startup time or minimum run time May not get started at all, especially if the startup is

more than 24 hours Long minimum run time May not get started at all because the cost is too high May not get shutdown when the prices are below cost

High minimum, low maximum MW, or low ramp rate May have to pay the market to generate (negative

price) May lose out on additional revenue from not producing

more MW

• Load may have to pay more than the generator revenue

6

But I wanted to “make money”• Assuming the market monitor does not flag

the generator for anti-competitive behavior (e.g. withholding or over-production)

• Unless the generator is “marginal” and “operationally constrained”, paid a higher price than the offer

• “Make whole” payments are not what you want

7

“Stop doing that” and trying to control the result!• Submit the real operational values, rather

than those to force an outcome

• Submit financial offers consistent with your costs

• Communicate with corporate and the market operator Problems Improvements

8



Mike Ducker Director, Market Analysis

Mitsubishi Hitachi Power Systems Americas, Inc.

Mitsubishi Hitachi Power Systems

Economic and Operational Benefitsof Improved CCGT Turndown

Michael DuckerDirector, Market Analysis

7/24/2017 1

© 2017 Mitsubishi Hitachi Power Systems Americas, Inc. All Rights Reserved.Proprietary and Confidential Information. This document or information cannot be reproduced, transmitted, or disclosed without prior written consent of Mitsubishi Hitachi Power Systems Americas, Inc.

0

5,000

10,000

15,000

20,000

25,000

Gen

erat

ion

(MW

h)

Hydro Nuclear Thermal Imports Other Renewables Wind Solar

A Day in the Life of California ISO March 26th, 2017 Case Study

-$144.22

$254.19

-$200-$150-$100-$50

$0$50

$100$150$200$250$300

Rea

l-Tim

e LM

P ($

/MW

h)

7/24/2017 2

$400/MWh price swing in 2 hours

Non-hydro ~20%Thermal ~12%




Is This Just Systemic for One-Day?

7/24/2017 3

2016

2017

$0

$10

$20

$30

$40

$50

$60

0 5 10 15 20 25

Rea

l-Tim

e LM

P ($

/MW

h)

Hour of the Day

$0

$10

$20

$30

$40

$50

$60

$70

0 5 10 15 20 25R

eal-T

ime

LMP

($/M

Wh)

Hour of the Day-$10

$0

$10

$20

$30

$40

$50

$60

0 5 10 15 20 25

Rea

l-Tim

e LM

P ($

/MW

h)

Hour of the Day

January February March

Mid-day trough deepening as late-day peak rising

$0

$10

$20

$30

$40

$50

$60

0 5 10 15 20 25

Rea

l-Tim

e LM

P ($

/MW

h)

Hour of the Day

April


Is This Just Systemic to CAISO?

1,130

586

278 206 18464 57

0

200

400

600

800

1,000

1,200

Aver

age

# of

Hou

rs (2

016)

Negative LMP Occurrences2016 – HUB Averages

7/24/2017 4

“Prices are so low that, in an unexpected move, hydroelectric generators are opting to let water spill over

their dams instead of producing electricity” -Tom Doughty, VP, Customer & State Affairs, Cal-ISO


How Best to Support the Flexibility Need

7/24/2017 5

0%

20%

40%

60%

80%

100%

120%

$0

$10

$20

$30

$40

$50

$60

0 5 10 15 20 25

Pla

nt L

oad

(%)

Rea

l-Tim

e LM

P ($

/MW

h)

Hour of the Day

2017 Combined Cycle Peaker

Natural Gas Supporting Renewable Integration:Optimizing between turndown and shutdown


MHPS-Tomoni VLL• Best Available Control Technology (BACT)

expands emissions compliance range• Customer benefits:

1. Greater operational flexibility to support grid volatility and complement renewables

2. Reduced fuel costs and emissions (CO2, NOx, CO, VOC, PM, etc) due to lower dispatchable load

3. Reduced maintenance costs and emissions due to fewer stop-start cycles

MHPS-Tomoni Very Low Load

7/24/2017 6

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

GT

or C

C L

oad

(%)

Normal Operational Range

Expanded Range

Hold Load


MHPS Case StudyActual GTCC Operation in WECC vs. Benefits with Tomoni Flex System

7/24/2017 7

050

100150200250300350400450500

2/3/17 0:00 2/8/17 0:00 2/13/17 0:00 2/18/17 0:00 2/23/17 0:00 2/28/17 0:00 3/5/17 0:00 3/10/17 0:00

GTC

C O

utpu

t (M

W)

20% Turndown 50% Turndown

Service Factor 88%

Capacity Factor 62% Levelized @ 1 month Base w/ Tomoni Flex Benefit

Fuel Cost @ $4.50/MMBtuDelivered

$5,940K $5,650K ($290)K

CO2 [email protected] lb-CO2/MMBtu 78,490 tons 74,670 tons (3,820) tons

NOx Emissions@ 0.006 lb-NOx/MMBtu 4.0 tons 3.8 tons (0.2) tons


How Valuable are More Flexible GTCCs?

$3,466,000

$1,733,000$867,000

$1,145,000

$572,000

$287,000

$4,681,000

$2,340,000

$1,171,000

$0

$500,000

$1,000,000

$1,500,000

$2,000,000

$2,500,000

$3,000,000

$3,500,000

$4,000,000

$4,500,000

$5,000,000

All Months ShoulderMonths

Spring OutageMonths

Yearly Savings if Similar Operation Applied During…

FuelCO2NOx

7/24/2017 8

Assumptions:• Fuel @ $4.50/MMbtu Delivered• CO2 @ $25/ton• NOx ERC @ $30K/ton• Shoulder months assumed Feb, Mar, Apr, Sep, Oct, Nov• Spring Outage Months assumed Feb, Mar, Apr

Up to $1-5M savings/year

corresponds to >$10-50M in NPV

for typical utility/IPP


7/24/2017 9

Thought Piece to End…

Will the Markets Brake or Break?


Will Markets Brake or Break?

What are simple MWh RPS standards causing?

7/24/2017 10

Renewable vs. Renewable Dichotomy

Flexible Resource Retirement

020406080

100

Jan-17 Feb-17 Mar-17

GW

hC

urta

iled

CAISO Renewable Curtailments↓ Flexible resource investment?↓ Renewable resource investment?↓ Market players (competition)?

↑ Market volatility / reliability concerns?↓ Market prices?• New Market Constructs?


Dispatchable Clean Energy Systems

7/24/2017 11

2016 CO2 Emissions:24% BELOW 2005 levels

https://emissionsindex.org/

Sources: US EIA, Lazard’s Levelized Cost of Storage Analysis v1.0; MHPS Research


Thank You

Mitsubishi Hitachi Power Systems

7/24/2017 12



John Wester Energy Market Manager

Austin Energy

Austin Energy Generation –Operating in the ERCOT Market

John WesterDirector Project and Asset Management


Austin Energy – Owned Generation Mix

2

Generation Type Total Capacity Ownership

Natural Gas – Conventional Steam 1 – 315 MW2 – 415 MW

100% Own and Operate

Natural Gas – Combined Cycle 1 X 1 - 300 MWs


Natural Gas – GTs 6 – 45 MW4 – 50 MW


Coal 600 MWs Own 50% of two 600 MW Units with LCRA – Operated by LCRA for AE

Nuclear 400 MWs Own 16% of two 1250 MW Units with NRG and CPS – Operated by 3rd Party


Austin Energy – ERCOT Market Impact

3

Generation is Regulated and Deregulated at same timeAustin Energy regulated in retail (captive customers)ERCOT continues to be regulated for T&D (socialized costs across market)All Generation competes in Wholesale Deregulated MarketPrice pressure from low natural gas and “0” fuel renewablesCost of Generation is the key to maintaining regulated benefits

ERCOT Nodal Market structure and generation mix currently rewards flexibility and can be unforgiving for baseload generation

Lack of the ability to cycle puts economic pressure less flexible generationDAM does not work well to economically dispatch units with longer start-up timesBalance of reliability, cost, environmental aspirations across ERCOT


Austin Energy – Strategies/Concerns

4

Operational changes at plants to increase flexibilityLower LSLs− Sliding Pressure for conventional steam – must maintain Droop

requirements− Lower ramp rates at low loads – adjust ramp and notify ERCOT

Reduce Start up times – minimize fuel burn, faster air emissions complianceDaily Cycling Large Conventional Steam Operate SC GT’s as price responsive

ERCOT challenge for adequate inertia as we move generation portfolio away from large rotating machines toward more intermittent resources non-controllable resources


Questions

5

?

Turbophase Dry Air Injection – Fast Ramp Power for Peak Power and

Renewable Firming

Brian Foley Director, Sales PowerPhase

Flexible Solutions Today for the Low Carbon / Renewable Energy

Future

Brian Foley Director, Sales

July 27, 2017

Powerphase Proprietary & Confidential

Agenda

Market Dynamics

Turbophase Overview

2

Technology Evaluation

Summary

$1 Trillion+ in New Power Generation Will be Built by 2035 and a large &

growing share will come from Natural Gas Generation and

Renewables.

Pressure on Coal & Nuclear 1Accelerating Renewable

Deployment2Requires Synergies

between Renewables& Conventional Generation

3

Low Carbon / Renewable Energy

Future

3

www. p o w e r p h a s e l l c .com 4Page |


Renewable Generation Driving New Approach

4

New Market Need:

• Fast ramp• Flexible• Low Carbon• Low Cost

Current Solutions:

• Cycling CCGTs• Aeroderivative GTs• Recip Gen Sets• Turbophase

Characteristics for dispatchable power resources (i.e. Firming Energy) in order to balance renewable energy supply variations.

Must be capable of dispatching and load following the renewable energy supply such that a constant value of scheduled energy is delivered

The Worlds First Gas Turbine Supercharger

5


Turbophase Helps Increase Plants Flexibility & Profitability

RETURN ON INVESTMENT• Energy• Reserve Margin• Ancillary

FAST RESPONSE• Eliminates spinning reserve• Flexible Dispatch• Dynamic Signal Capable• Provides renewable firming

OUTPUT INCREASE• Increase Power• Temp, Humidity,

Elevation Independent

PARTS LIFE IMPROVMENT• No water, steam• No change to firing

temperature

ENVIRONMENTALLY FRIENDLY• No Water Consumption• SCR, CO Catalyst

IMPROVE EFFICIENCY• GT efficiency improvement

6


Modular, Flexible System

7


Standard Products Ensure Reliability

• Standard commercial off the shelf components

• Leading OEM Gas / Diesel Engine Manufacturers

• Worlds Top Performing “Oil Free” Intercooled Compressor MFGs

• Sound & Weather Enclosure

• Fully Assembled and Factory Acceptance Tested

8


9

Technology Evaluation -Methodology and Results


10

Firming Energy Technology Evaluation

Analysis Methodology/Inputs• Modeled a 50 MW on-peak Firming Energy product:

o Two (2) LM2500+G4o Three (3) W50SG recip gen setso Eight (8) Turbophase modules (installed on a F-class CC plant)

• Used 2016 ERCOT real time hourly data - energy prices, natural gas costs, generation asset dispatch profiles

• Factored in dispatch cost for each firming resource - aero/recip/TPM• Considered sale of surplus energy (above that required for firming)

Results/Output• Market based economics for each firming technology to include:

o Total Installed CAPEXo Total Annual Firm Costso Merchant Energy sale margino 20-year “All-In” Costs or Profit


11

Firming Technology Capital Costs

*In PJM, the LM and WRE technologies were not dispatched to provide firming service as the PJM market provides for the purchase of real time energy for balancing purposes at a lower cost

*

• CAPEX includes – EPC, Interconnect, Interest, Permits

• Turbophase provides lowest upfront costs for Firming Energy


12

ERCOT Summary

• Turbophase is available whenever the CCGT plant is running• Cost to run includes Firming Energy purchase when CC is offline (out of the money)• Turbophase generates MWs at CC Heatrate (so dispatches with CCGT)• Turbophase generates significant Merchant Energy sales

Turbophase Provides Positive Net Income vice Net Cost of Other Technologies


13

ERCOT 20-Year Cost/Margin Summary

• Costs include CAPEX O&M (fuel + variable), and real time energy purchases• All technologies are compared to 100% Real Time Buy Through

Turbophase Provides Significant Value Over Competing Technologies


14

Summary

• Renewable Generation Driving Need for Firming Energy Resources• Numerous options are available

o Cyclic CCGTo Aeroderivativeo Reciprocating Engine Gen-setso Turbophase

• Key Factors for Technology Selection: o CAPEXo Cost of Generationo Lifecycle revenue/margin

• Turbophase is a viable option• Low Cost• Flexible• Fast Ramp• Low Carbon


15

Turbophase – Generation Smart

Questions?

Brian FoleyDirector, SalesPowerphase [email protected]+1 (720) 288-3003


16

Turbophase – Generation Smart

Backup


17

PJM Summary

• Turbophase is available whenever the CC plant is running• Cost to run includes Firming Energy purchase when CC is offline (out of the money)• Turbophase generates MWs at CC Heatrate• Turbophase generates significant Merchant Energy sales

Turbophase provides for positive Net Income


18

20-Year Cost/Margin Summary


Energy Dense System - 54MWs

19

JK1

Slide 19

JK1 Josh Kraft, 11/28/2016


Turbophase Power Plant Integration

Site Utilities and Connections o Power – 4160VAC, 100 amps for TPS, 60 Hzo Control/Interface – TPM Onboard HMI and

Local HMI in Control Room (Fiber Optic)o Fuel – Natural Gas – 20.5 mmbtu/hr per TPM

o CT increases 24 mmbtu/hr Per TPMo Closed Loop Cooling – Consumes Zero o TPM Foundation – 18” Thick x 8’ x 40’ o Project Area Dimension – 100’ X 100’o Drainage - 8 GPM of condensate piped to

raw water forwarding sump

Installation / Integrationo TPM common air header to all CTs

• TPM air pipe to IBH o Turbophase Electronic Enclosure (TPEE)

receives 4160 power, distributes 480o TPEE Receives Fiber Optic and distributes to

modules (Mod Bus or TCP/IP)o Connect to fuel gas skid near SCCT before

Isolation Valve, TPS regulates Pressure and Flow

20


Tie into Gas turbine and borescope took less than one day

Balance of installation was complete 90 days after notice to proceed:• Air line• Gas line• Air pulse Pre-filter

• Closed loop cooler• 2 Modules• Controls

2 ModulesAir and gas line

Air tie into IBH or RAC line

Gas tie in

Pulse air pre-filter

Installation is Simple and Fast

21


Low Maintenance Costs

Maintenance Estimate Including Major Overhaul

$0.003 / kWh

22


Installations in progress globally:7FA, 501F, 9FA, 701F, FT8, Fr5, 6B, LM6000, RB211

Turbophase Flexibility Being Deployed Globally

23

LNG Infrastructure – Distributed Liquefaction

Edward Woods Territory Sales Manager, Distributed LNG

Solutions Siemens

2015-07-30

Strictly Confidential

Page 1 Walhof / Distributed LNG Solutions

Strictly Confidential dresser-rand.com

Micro-Liquefaction and Use ofOnsite LNG

Distributed LNG Solutions

2015-07-30



Table of Contents

• Demand Side Markets for distributed LNG 3

• Supply Side Markets for distributed LNG 6

• Micro-Liquefaction System Overview 7

• Micro-Liquefaction System Base Equip. 8

• Micro-Liquefaction System Optional Equip. 9

• Micro-Liquefaction System Perf. 10

• Gen. Arr. - Micro-Liquefaction System 11

• Micro-Liquefaction System Flow Dia. 12

• Example Installations 13

• Example Project 16

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E&P Equipment: Drilling/ Fracturing

• Significant per gallon equivalent fuel savings to diesel

• High horsepower equipment (>6% of 1800 unit fleet use CNG/LNG)

Mining, Rail, and Marine

• Significant fuel cost savings

• High horsepower equipment (>1,000 gpd per unit typical) (i.e. 700 mining units in PRB)

Retail/Utility LNG Supply

• Low cost, low risk market seeding

• Early cash flow accelerator market for large scale plants under construction (30-60 months)

Local, low-cost alternate fuel source for diesel, propane, and heating oil users

Distributed LNGDemand Side Markets

Typically distanced from large LNG supplies

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Distributed LNGDemand Side Markets – Power Generation

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Distributed LNGPJM Capacity Performance – Onsite Fuel Storage

• Driven by Polar Vortex• Concern with gas pipeline being ‘sucked dry’• Ensures capacity during peak demand (72 hours for Nat Gas plants)

2015-07-30



Gas Pipeline / Gathering Systems

• Pressure control for pipelines

• LNG production for power generation

• Debottleneck gathering systems

• Back-up supply for pipeline outage, high demand periods or interrupted service

Local, low-cost gas supply to produce LNG to offset diesel and propane

Distributed LNGSupply Side Markets

Flares

• Eliminate environmental concerns and monetize flares

• Flares are typically associated gas or lower value processed gas (requires optional gas pre-treatment)

• 5.2 TCF/yr flared worldwide = ~180 million gpd of LNG

Stranded Wells

• Monetize stranded wells by converting to LNG

• Typically found in newly developed gas fields or at the edge of existing fields with immature gas gathering infrastructure

• LNGo provides low cost, short term alternative to pipelines

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• Modular system converting natural gas to liquefied natural gas (LNG)

• Micro-scale, point of use (example systems)

• LNGo LP system – up to 7,000 GPD (11 tpd)

• LNGo HP system – up to 30,000 GPD (48 tpd)

• Re-deployable, skid mounted design with small footprint

• Utilizes industry proven technologies and service

• Liquefaction cycle uses feed gas as fuel*, refrigerant, and liquefied product

* If power module is included.

• Self powered available - easy to permit

Micro-Liquefaction SystemsOverview

2015-07-30



Feed/Flash Booster – FFCM Primary Compressor Module - PCM Process / Chiller –PRM/MCM

Controls & MCC

Elevates the pressure of the feed gas and the returning flash to the optimal liquefaction pressure.

Compressor provides the main compression energy required by the efficient turbo-expansion process.• Proven D-R MOS™ reciprocating

compressor technology • Non-lubricated cylinders and

packing (no process contamination)

• VFD with induction motor for process turndown

Turbo-expansion with pre-cooling refrigeration loop. This closed loop natural gas concept means working fluid is integral and utility needs are minimized.• Cooling and product phase change

from gas to liquid• Mechanical chiller with stainless

cryogenic heat exchangers and evaporative cooling

• Turbo-expander and Joule-Thompson (J-T) valve (methane refrigerant)

Complete control of all modules of the LNGo LP and HP systems. Remote capable control logic with wireless instrumentation and transmitters used wherever advantageous and code compliant.

LNGo-LP N/A 4 Throw / 4 Stage Ammonia as cooling media Integrated into power module where applicable

LNGo-HP 4 throw / 2 stage 2 throw / 2 stage Propane as cooling media Separate module or in client control room

Micro-Liquefaction System Base Equipment

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Gas Conditioning Module - GCM Power Module LNG Storage Balance of Plant

Gas cleanup system with drying in order to remove CO2 and water from the incoming feed gas stream. Clean, dry gas insures optimal liquefaction performance. Additional conditioning module available for laden gas depending on composition.• Removes CO2, H2O, and

heavy hydrocarbons (C3+)

Option to be grid-independent and a fully self-powered liquefaction system. This is achieved by leveraging the waste gas stream for power generation.• High tech, low emission rich burn

with NSCR catalyst • D-R Guascor natural gas

powered 1 MW power system• Purge flow from cleanup module

is blended into the fuel supply to power the Guascor engine

• D-R Enginuity® Control and Monitoring Systems

• No flaring required. Purge flow from gas conditioning is blended into the fuel supply to the Power Module.

Storage strategies provided to accommodate the client’s needs. From bullet to atmospheric tanks with vapor recovery, any storage need can be addressed through a network of approved vendors.

Project resources to provide procurement execution of all project details such as site preparation, cryogenic pumping, boil-off gas recovery etc.

Gas clean-up• NGL removal equipment as

required for NGL removal. This is dependent on gas composition provided by customer.

LNGo-LP Molecular Sieve Pressure Swing Absorption (PSA)

One (1) required Vertical or Horizontal Scope as defined by customer.

LNGo-HP Temperature swing Absorption (TSA)

Two (2) required**Dependent on gas composition

Vertical or Horizontal Scope as defined by customer.

Micro-Liquefaction System Optional Equipment Overview

2015-07-30



Micro-Liquefaction System Performance Overview

LNGo LP system LNGo HP systemInlet Conditions

PressurePsig 35 - 50 615 – 1,200Barg 2.4 – 3.4 42.4 – 82.7

Gas FlowMMscfd .781 2.500NM3/Hr 970 3,104

LNG Production Information

CapacityGal/day 7,000 30,000Liter/day 26,498 113,562Ton/day 11 48

Delivery Conditions

PressurePsia ~30 ~30Bara 2.07 2.07

Temperature°F -253 -253°C -158 -158

Power

Energy ConsumptionHP ~1,341.02 ~2,682.044kW ~1,000 ~2,000

Power SourceGrid Base Base

On site Option Option

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Configuration for markets with pipeline quality gas input at 50 psia shown

Power moduleGenset driven by Guascor 1MW engine consumes purge gas from mole sieve to power unit

Conditioning module Molecular sieve removes CO2and H2O. The purge flow, with C2 and above, is blended into the fuel supply to the Guascor engine

Compressor module MOS™ compressor drives efficient process

Process moduleDelivers 7,000 gpd (11 tpd) LNG

Enginuity® control and monitoring systems

Micro-Liquefaction SystemGeneral Arrangement

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Micro-Liquefaction SystemFlow Diagram

LNGo ™ cycle uses methane as the fuel, refrigerant and liquefied product.

NG = Natural GasHX = Heat Exchanger (welded plate and frame)

Input – Processed natural gas

Flow .781 MMSCFD

Temperature 60° F 15.5° C

Pressure > 50 psia > 3.4 bara

Output – Liquefied Natural Gas (LNG)

Flow 7,000 GPD 11 TPD

Temperature -253° F -158° C

Pressure 30 psia 2.07 bara

* Dependent on gas composition and pressure

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Micro-Liquefaction System Example Installation

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Micro-Liquefaction SystemNorthern Canada

Commissioning October 2016

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Micro-Liquefaction SystemFeatures and benefits

• 7,000 – 30,000 gpd (11 - 48 tpd) production - perfect size for local LNG production and demand

• Small footprint• Self-powered available - easy to permit• Large-scale LNG industry components utilized• Short cycle time order to operation• Multi-market applications• Worldwide service and support

2015-07-30



Onsite Distributed LNG - Example ProjectsLongview Power - WV

• Gas used to start power plant / support high demand• Pipeline gas was not reliable when re-firing during critical times• Onsite LNG with vaporization• ‘Inside-the-fence’ startup capability• Meets PJM capacity performance requirements

2015-07-30



Distributed LNG Solutions Contact

Edward WoodsTerritory SalesDresser-Rand / Global Solutions / Distributed LNG Solutions

4700 McMurry Ave., Ste 101Fort Collins, CO 80525

Mobile: +786 602-3207

E-mail:[email protected]

http://lng.dresser-rand.com

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