2008 Long Term Acquisition Plan

Transcription

1 2008 Long Term Acquisition Plan APPENDIX J2 AMEC Report on Alternative Configurations for Burrard Page 1 of 215

2 16 May 2008 RP Revision 0 Page 2 of 215

3 16 May 2008 Mr. Tom Coyle Mr. Craig Godsoe Director, Major Capital Projects Solicitor & Counsel British Columbia Hydro British Columbia Hydro 6911 Southpoint Dr., 17th floor Dunsmuir Street Burnaby, BC V3N 4X8 Vancouver, BC V6B 5R3 Canada Canada Dear Tom and Craig, (TGS) Alternative Configuration Study Supplemental Report - Task 3 LMS 100 SCGT As per our Agreement and its associated change order, we have completed the LMS 100 SCGT Supplemental Report to the Task 3 Alternative Configuration Report. The report provides supplemental material on LMS 100 SCGT options not originally addressed in the Task 3 Report, Alternative Configuration Study for a Repowered Burrard TGS. It included recommended capital, and OMA cost estimates, emissions for two configurations using three LMS 100 SCGT and one containing four LMS 100 SCGT. I trust that the report satisfies your needs based on our scope and discussions over the last couple of months. Thank you for the opportunity to work on this very interesting project. Yours truly, Blair Seckington Director, Power Technology Direct Tel.: Direct Fax: blair.seckington@amec.com BRS/brs c: R. Livet AMEC Americas Limited 2020 Winston Park Drive Suite 700 Oakville, Ontario Canada L6H 6X7 Tel (905) Fax (905) Page 3 of 215

4 CONDITION ASSESSMENT AND ALTERNATIVE CONFIGURATION STUDY BURRARD TGS May 16, 2008 BURRARD TGS ALTERNATIVE CONFIGURATION Supplemental Report LMS 100 SCGT Options Task 3 Alternative Configuration Blair Seckington 16 May 2008 Prepared by: Date Dr Nat Natarajan 16 May 2008 Checked by: Date Bob Livet 16 May 2008 Approved by: Date Rev. Description Prepared By: Checked: Approved Date A Draft Report B Seckington N. Natarajan R Livet 9 May 08 0 Final Report B Seckington N. Natarajan R Livet 16 May May 2008 RP Revision 0 Page 4 of 215

5 IMPORTANT NOTICE This report was prepared exclusively for BC Hydro by AMEC Americas Limited. The quality of information, conclusions and estimates contained herein is consistent with the level of effort involved in AMEC Americas Limited services and based on: i) information available at the time of preparation; ii) data supplied by outside sources; and iii) the assumptions, conditions, and qualifications set forth in this report. This report is intended to be used by BC Hydro only, including as support for BC Hydro s regulatory filings with the British Columbia Utilities Commission (BCUC), subject to the terms and conditions of its contract with AMEC Americas Limited. Any other use of, or reliance on, this report by any third party for purposes unrelated to BC Hydro s regulatory proceedings before the BCUC is at that party s sole risk. 16 May 2008 RP Revision 0 Page 5 of 215

6 EXECUTIVE SUMMARY BURRARD TGS ALTERNATIVE CONFIGURATION Supplemental Report LMS 100 SCGT Options Task 3 Alternative Configuration Burrard TGS offers a reasonable opportunity for an LMS 100 SCGT gas turbine modification, where improvements in environmental performance are required and regulatory or generation futures uncertainty makes a combined cycle impractical. Its major drawbacks are its high $/kw cost and its modest improvement in efficiency over existing Burrard TGS steam turbine units for peaking purposes and its low efficiency and hence fuelling economy compared to a combined cycle for base load generation. The major conclusions of this assessment are: 1. LMS 100 SCGT implementation of three or four units (300 to 400 MW) would likely not take place before mid 2014 at the earliest. 2. Air emissions will increase with increased generation levels, regardless of which technology is employed. The absolute value at any particular generation level is minimized by use of CCGT, followed by LMS 100 SCGT. 3. Existing Units 1 to 6 will need significant investment (spares purchases and detailed inspection and purchases as required) to ensure their high availability/reliability capability to the LMS 100 SCGT in-service dates and for Units 4 to 6 and possibly Unit 3 for the period 2014 to The LMS 100 SCGT has higher efficiencies than the existing Burrard TGS units and heavy frame SCGT and will tend to run ahead of any existing Burrard TGS units helping to extend their life and reduce their fuelling costs. 5. LMS 100 SCGT capital costs are likely between $850 and $900/kW (2007$) for a turn-key lump sum EPC contract, including high temperature SCR and CO catalyst. 6. LMS 100 SCGT have a relatively high capital cost per kw. Their higher cost justification likely depends on there being considerable regulatory and/or generation futures uncertainty. This may make a case for them versus either less efficient, less environmentally friendly heavy frame SCGT peakers or more efficient, more environmentally attractive, base loaded CCGT that may also be difficult to permit due to their high absolute emissions (due to higher generation levels). 7. Current air emission of effluent permit limits for Burrard TGS should not be a significant issue with LMS 100 SCGT applications. BACT measures in PSD areas of the United States could be applied. Some special measures to manage particulate matter and ammonia emissions within existing Burrard TGS permit criteria (g/m 3 ) may be needed. Measures to minimize noise to the local environment may be adopted, but will tend to have modest negative impacts on SCGT and CCGT performance (capacity, efficiency). 8. A staged approach to implementation (two LMS 100 followed later by a further one or two) might be considered as part of a system optimization. 9. A detailed system analyses is required to determine optimal technology selection, particularly given the particular system resources, demands and constraints in the BC Hydro system, its inter-connected neighbours, and fuel supply systems. 16 May 2008 RP Revision 0 Page S1 Page 6 of 215

7 Table of Contents EXECUTIVE SUMMARY... 1 Table of Contents Task Definition and Approach Burrard TGS Background Facility Modification Basis of Estimate Common System, Cost, Performance, and Environmental Information General Facility Description Plant Layout Schedule Capital Cost OMA Cost Environment Performance Fuelling Cost Scenario A1 600 GWh/yr peaking Operation Operating Pattern OMA Cost Cashflow Environment Scenario A GWh/yr, Intermediate with Seasonal Base Load Operating Pattern OMA Cost Cashflow Environment Scenario A GWh/yr, Year Round Base Load Operating Pattern OMA Cost Cashflow Environment Summary GLOSSARY May 2008 RP Revision 1 Page TC1 Page 7 of 215

8 BURRARD TGS ALTERNATIVE CONFIGURATION Supplemental Report To Task 3 Alternative Configuration LMS 100 SCGT Options 1. TASK DEFINITION AND APPROACH 1.1. Task Assignment The task is to prepare a Supplemental Report to the existing Task 3 Report on Burrard TGS Alternative Configuration for two LMS 100 options, documenting the conceptual design, preliminary cost estimates, and efficiency and environmental performance for a 20 year life, from 2008 to 2028: replace two existing Burrard TGS units with three LMS 100 simple cycle gas turbines (SCGT) or equivalent replace three existing Burrard TGS units with four LMS 100 SCGT or equivalent For both of these configurations, the following scenarios were examined: Scenario A1: 600 GWh/yr of winter peaking generation (Average 600 GWh/yr; Range of 200 to 1500 GWh/yr) Scenario A2: 3000 GWh/yr of intermediate capacity providing seasonal base load and intermediate generation through most of the year, with little or no summer generation Scenario A3: 6000 GWh/yr of year round base load generation This report describes the feasibility of the new facility equipment configurations for the scenarios above with descriptions of equipment, conceptual design, preliminary cost estimate and expected air emissions (including GHG emissions). 16 May 2008 RP Revision 0 Page 2 Page 8 of 215

9 2. BURRARD TGS BACKGROUND 2.1. Site and Station Background The Burrard TGS background material can be reviewed in the Task 1 and 2 Burrard Current Configuration Report and in the Task 3 Burrard TGS Alternative Configuration Report Permits Modification of Burrard TGS to replace two existing units with three LMS 100 SCGT or three of the existing Burrard TGS units with four LMS 100 SCGT requires that existing Burrard TGS permits for site capacity, water management, and air emissions be considered. The modified site nameplate rating with the LMS 100 SCGT units would be equal to or less than the current nameplate rating of the station, whether considered to be 905 MW or MW. The existing air emission limits for Burrard TGS are expressed in grams per cubic meter at standard temperature and pressure (g/m 3 at 3% O 2, 0 o C). Maintaining these same limits for LMS100 SCGT and CCGT options does not credit them with the saving due to their higher efficiencies. It is a possibility that the existing permit limits for ammonia slip and for particulate matter may be difficult to meet, even with BACT control levels. The ammonia slip may be overcome through a shorter catalyst life or more catalyst. The particulate matter is unlikely an issue given existing differences between permit levels and actual emissions in tests that would likely also occur with the gas turbine options. The existing Effluent Permit No. PE restriction of 1.7 million cubic meters per day and an upper bound of 27 degrees Celsius do not impact the LMS 100 concepts. The LMS 100 SCGT uses cooling water for its unique gas turbine intercooler, but substantially less than that of the condenser cooling water of any existing steam turbines being replaced, less than 3% of the maximum permitted amount. It could also use demineralized water for NOx emissions control if desirable or if dry low NOx combustion technology experiences developmental delays, but the quantities are well below any limits on fresh water from Lake Buntzen (about 21% of the current per unit per day maximum allowed). The modification of Burrard TGS with some LMS 100 SCGT units may result in the GVRD, the permitting agency, imposing new strict Air Emission Permit standards comparable in stringency to those set out in PSD (Prevention of Significant Deterioration) Permits in jurisdictions in the United States such as California, Washington, or Massachusetts. It would likely have limits similar in nature to those for the PSD Permit for the proposed SE2 660 MW CCGT that would have been sited in Sumas, Washington State in the same airshed as Burrard TGS. For this study, the LMS 100 SCGT units were assumed to have to meet: BACT for NO x, carbon monoxide (CO), ammonia (NH 3 ), sulphur dioxide (SO 2 ) NO x : SCR to less than or equal to 5 ppm vd (by volume, dry, 20 o C, 15%O 2 ) CO: Catalytic Reduction to less than or equal to 5 ppm vd (by volume, dry, 20 o C, 15%O 2 ) 16 May 2008 RP Revision 0 Page 3 Page 9 of 215

10 Sulphur: Natural gas maximum sulfur content limits Ammonia (NH3): slip to less than or equal to 5 ppm vd (by volume, dry, 20 o C, 15%O 2 ) at end of SCR catalyst life Conditions and Time Limits on Start-Up and Stop Times and transitional performance Emissions Rate and/or Annual Limits (to be defined) on significant emissions of NOx, CO, volatile organic compounds (VOCs), particulate matter smaller than 10 microns (PM10 combined filterable and condensable), sulfur oxides (SO 2 and SO3 or H2SO4 measured as SO2), sulphuric acid mist (H2SO4), and ammonia. Continuous Emissions Monitors (CEMs) on key effluents 16 May 2008 RP Revision 0 Page 4 Page 10 of 215

11 3. FACILITY MODIFICATION 3.1. Background - Fossil Generation Cycles The context of the Burrard TGS Alternative Configuration concepts is presented in Section 3.2 of the Task 3 Report LMS 100 SCGT Configuration The LMS 100 SCGT concept is similar to that illustrated in Figure 3-1. The gas turbine itself is a hybrid of a heavy frame gas turbine (the SCGT considered in Scenario A1 in the Task 3 report) and an aircraft jet engine. It has multiple turbine shafts within it that drive independently the air compressor section and an electric generator. Further the LMS 100 is unique among gas turbine electricity generators in that it has inter-stage compressed air cooler, an intercooler, that results in a more powerful and more efficient engine. The LMS 100 SCGT consists of six main parts: The air compressor The intercooler The combustor The gas turbine (multiple shafts) The electrical generator The Selective Catalytic Reduction (SCR) device and ammonia system for NOx and CO Figure 3-1 Simple Cycle Gas Turbine (SCGT) 16 May 2008 RP Revision 0 Page 5 Page 11 of 215

12 In addition, there are the Balance of Plant systems which include systems such as the Air Intake, Exhaust Stack. The air compressor sucks air through the air intake and filter and compresses it to about 40 times atmospheric pressure, much higher than for a heavy frame gas turbine. As the air is compressed, it heats up. The LMS 100 uses a dedicated turbine to drive its high efficiency compressor, but it still uses a significant portion of the turbine s gross power. The compressed air at mid-stage is channeled to a water cooled intercooler to lower its temperature and allow further compression to occur more efficiently. It is very important that the contaminants in the air entering the compressor are minimized to ensure continued high efficiency and longer reliable life. The compressed air is then fed to the combustor. The combustor combines the air from the compressor with fuel (natural gas at Burrard TGS) and burns them at very high temperatures. The natural gas must be at high pressure (about 850 psi) requiring for Burrard TGS a significant on-site natural gas compressor. Gas turbine combustors for the LMS 100 are currently water or steam injected to reduce NOx emissions. A dry low NOx version is expected to be available shortly and is assumed utilized in this case. Any of these three versions could be applied and generate about 25 ppm NOx (at 15% O2, dry, by volume). Balancing highly efficient combustion with low emissions of NO x and CO and other unburnt carbons is a prime consideration. Unlike the boiler in the CSC case, a SCGT uses much more air per MWh typically SCGT flue gas contains 13-15% unburnt oxygen versus only 3-5% for a CSC. The hot gas from the combustor is directed to the gas turbine which contains multiple rows of high temperature, high velocity turbine blades. These extract energy from the hot gases similar to how a steam turbine extracts energy from steam. The gas turbine rotates in turn driving an electrical generator, as well as the air compressor section. The flue gas leaving the LMS 100 gas turbine is typically between 800 o F and 850 o F much less than the 1000 o F and 1100 o F for a heavy frame 7F class gas turbine. This makes the use of a conventional or higher temperature, higher cost SCR catalyst practical, enabling NOx and CO to be reduced to 5 ppm. The SCR is located in a chamber in the flue gas ductwork that is similar to the heat recovery steam generator (HRSG) used in a combined cycle gas turbine (CCGT) The LMS 100 SCGT is a major new development of the gas turbine sector focused on the larger peaking to intermediate generation market. It nominally produces between 90 and 100 MW per machine. Its efficiency can reach 40% versus the 32% to 35% efficiency for a heavy frame SCGT and for the existing Burrard TGS steam cycle units. There is a small but rapidly growing amount of experience, but there remain the risks associated with any new gas turbine technology, including the demonstration low NOx burners. The engine has however a solid base of experience with similar designs in the aero market. The LMS 100 has a number of features well suited to the application at Burrard TGS: Moderate size footprint - 3 or 4 units fit within confines of Burrard TGS Good simple cycle efficiency (37% to 40%) 16 May 2008 RP Revision 0 Page 6 Page 12 of 215

13 Low NO x (25 ppm burners) with SCR capability to meet industry BACT of 5 ppm Quick start-up and shutdown 10 minutes and rapid turndown response rates Simplicity and speed of installation very modular Available in outdoor (individual noise/weather) enclosures or indoor building applications A negative aspect is that there is no competitive marketplace for either the procurement or maintenance of these units. There are no comparable competing units at this moment in the size range and no after-market parts or maintenance providers. Figure 3-2 Aeroderivative GE LMS 100 SCGT (Ref: General Electric LMS 100 Sales Literature) The Burrard TGS LMS 100 SCGT plus SCR installation would have an additional chamber between the turbine and the stack for the SCR and CO catalyst and would have a water to water heat exchanger instead of the cooling tower shown in Figure May 2008 RP Revision 0 Page 7 Page 13 of 215

14 4. BASIS OF ESTIMATE The estimates given herein are based on the following: 1. Capital and OMA estimates are Order of Magnitude quality, mid-2007 Canadian $$ costs, with no escalation or interest - a pre/early conceptual stage of any project which is consistent with BC Hydro s planning criteria of +30%/-15%. 2. Client supplied mandate for high reliability and 20 year life 3. Client supplied equipment condition reports and studies 4. Client information on existing Burrard TGS operating pattern and costs 5. LMS 100 SCGT estimates are based primarily on recent total project costs for comparable SCGT and CCGT projects, adjusted using conceptual software to reflect ballpark, but reasonable differences for a Burrard TGS brown-field installation. The estimates reflect: A conservative project management basis lump sum, fixed price, turnkey pricing carrying an inherent and fairly substantial EPC risk premiums. Little change in pricing for major equipment in Canadian dollar terms despite recent Cdn/US exchange rates. Little change reflecting a recently increasingly tight market for new SCGT and CCGT, for specialized equipment and materials, for skilled labour. 6. Some moderately large existing Burrard TGS plant maintenance costs have been identified as single year values, but may in fact require prepayments/ stepped costs over some years. 7. The cost timing assumes that no decision on approach is taken before fall 2008 (FY2009) as part of BC Hydro s approvals process and hence any significant capital decisions are not taken until then impacting possible implementation time-frames. 8. Based on BC Hydro direction, decisions on proceeding are assumed not to occur until fall 2008 and that it would take: i) a further 7 to 12 months to get government and public reviews done and further concept studies undertaken; ii) 36 months to get all the necessary environmental assessment and associated permit approvals; and iii) major equipment and/or EPC contract awards, demolition as necessary, and then about 24 months for the LMS 100 SCGT retrofit leading to a roughly Spring to Fall 2014 earliest in-service date. 9. Study timeframe has been limited to 2008 to 2028 (20 years), covering essentially BC Hydro Fiscal Year FY2009 through FY2028. No attempt has been made to assess the termination value of the SCGT option at the end of the period or any decommissioning costs. 10. Demolition costs have been based on a net value demolition costs the value of steel/salvageable equipment based on recent Ontario experience. 11. Operation and Maintenance (O&M) costs are based on load pattern and load following requirements as defined by BC Hydro and interpreted with BC Hydro review and acceptance for study purposes (not necessarily concurrence for regulatory purposes). 12. SCGT OMA costs are based on vendor LMS 100 information and on data for heavy frame SCGT from past projects. It should be treated as indicative, especially considering the current limited experience with LMS 100 SCGT and Long Term Service Agreements for such machines. 16 May 2008 RP Revision 0 Page 8 Page 14 of 215

15 13. OMA costs can be very dependent on a variety of factors. For this reason there is a wide range of data in the public forum. Some of the factors that can significantly affect these costs include: Specifics of assumed and actual operating pattern over a short period, let alone 20 years (numbers of starts/stops; peaking vs. intermediate vs. seasonal base vs. base load), can impact total costs but less so in the case of an LMS 100; Contract specifics and market conditions at the time can impact total costs; Distribution of load between existing Burrard TGS units and SCGT units can significantly impact total incremental costs; Risk aversion use of Customer Service Agreements for differing periods of time and for different scopes of supply (routine parts, unplanned and routine parts, labour, monitoring, gas turbine (GT) only, etc.), as well as insurance schemes, non original equipment manufacturer (non-oem) parts and labour usage. This can significantly impact the split of Variable vs. Fixed OMA charges in any given year and accounting/regulated rate practices; Sparing practices equipment, units, etc.; Start-up fuel and power supply and accounting (excluded herein); Existing and Incremental staff and labour rates and accounting. 14. Existing Burrard TGS unit OMA and capital programs depend on which units are needed in the interim and long term for what role and on the acceptable failure risk. It is assumed that existing Burrard TGS Units will continue to operate for capacity as best as possible until replaced and synchronous condenser capacity is accommodated by modifying some of the remaining existing Burrard TGS units (Unit 4 is already capable). 15. Excludes major switchyard operations or changes. 16 May 2008 RP Revision 0 Page 9 Page 15 of 215

16 5. COMMON SYSTEM, COST, PERFORMANCE, AND ENVIRONMENTAL INFORMATION 5.1. General Two sub-scenarios are examined featuring either three or four LMS 100 SCGT units. The following comments apply to both of these cases: It is assumed that no future capability for combined cycle conversion is required. NO x emissions and ammonia must meet BACT standards: NOx of 5 ppm (dry low NO x or water/steam injected combustors to 25 ppm and 80% SCR); NH3 of 5 ppm (at end of catalyst life). Existing facility permit levels for NO x, water usage, etc. must not be compromised Existing facility permit levels for ammonia and particulate matter of 10 g/m 3 can be managed through modest additional measures, if measures beyond BACT are required Permits will likely necessitate some form of start-up/shut-down transient conditions Permitted emission limits will be strict, as similar as practical to those identified with the proposed SE2 660 MW CCGT which would have been sited in Sumas, Washington State in the same airshed as Burrard TGS Gas supply is optimized, including dispatch, to allow unhindered unit dispatch Noise will be approximately 58 dba at plant boundary Stacks, (normally 50 to 60 feet for SCGT) have been modeled at 150 feet to avoid impingement on existing unit structures and surrounding higher landscape The LMS 100 SCGT option has several positive and negative features, both general and Burrard TGS specific, which must ultimately be addressed in both planning studies and in actual implementation: Higher start up NO x levels, but for very brief times Modestly lower capacity with high ambient temperature for dry low NOx combustors (evaporative cooling can help somewhat) Moderate space requirement due to intercooling requirement Gas pressures required are much higher, necessitating large on-site compressor Load swings and two shifting can be readily followed, but can result in gas-electricity dispatch interface issues technical and economic implications (not consistent with current roughly 150 MW/day swing permissible under gas supply agreement at Burrard TGS) Requires substantial rock removal and disposal from east side of current Units 1 to 3. Flatter turndown limits while maintaining high efficiency and low NO x (benefit) Very short start/stop times typically 10+ minutes allowing for shorter uneconomic start-up times and lower efficiency stages (benefit) Low NO x (5 ppm at 15% O2). Existing Burrard TGS units on gas with SCR (17-25 ppm permit at 3% O 2 = about 7 to 10 ppm at 15% O 2 equivalent). Reduced start-up/shut-down, warm-up times, and low load out-of-merit operating times may enhance this reduction 16 May 2008 RP Revision 0 Page 10 Page 16 of 215

17 SCGT has moderate water requirements for intercooler cooling from Burrard Inlet and if dry low NOx burners are used minimal fresh water from Lake Buntzen (benefit) May allow more flexible and effective use of existing Burrard TGS steam units (benefit) 5.2. Facility Description Three or four LMS 100 units were selected for consideration. This appeared optimal based on site space availability, moderating capital investment in an uncertain environment, and providing spares for enhancing the availability and reliability of the remaining existing Burrard TGS units that would continue in operation. Concept 1: Three LMS 100 SCGT with an SCR+CO catalyst chamber are installed for a total capacity of about 300 MW. Existing Burrard TGS Units 3 to 6 are retained more or less as is, with re-investment a function of the generation level and role. The total operating capacity of the modified facility would thus be approximately 900 MW. The SCGTs will not enter service until 2014 at the earliest and Burrard TGS still needs to be a reliable supplier as per Task 1 and 2 Report Scenario 1. Given this, much of the work and capital investment on Units 3 to 6 would apply in the years 2009 to After the SCGTs enter service, Units 4 to 6, and especially Unit 3, are assumed to see minimal operation under peaking conditions, but substantial service under higher generation scenarios (Burrard TGS 6000 GWH Scenario 3). Existing Units 1 and 2 will also still need to be reliable suppliers as per the Task 1 and 2 report Scenario 1 until the SCGT units come into service. Some of the work and capital investment set out in the Task 1 and 2 report for Units 1 and 2 would apply in the years 2009 to Once the SCGTs are operational, Units 1 to 2 can be decommissioned or demolished and parts used to maintain Units 3 to 6, minimizing further capital expenditure on these units. Concept 2: Four LMS 100 SCGT with an SCR+CO catalyst chamber are installed for a total capacity of about 400 MW. Existing Burrard TGS Units 4 to 6 are retained more or less as is. The total operating capacity of the modified facility would thus be approximately 850 MW. In this sub-scenario, only Units 4 to 6 are retained. The SCGTs will not enter service before 2014 at the earliest. The capital investment on Units 4 to 6 would apply in the years 2009 to 2012, as well as some of the modest planned expenditures on Units 1 to 3 in that period. After the SCGTs enter service, Units 4 to 6 are assumed to see minimal operation and existing Units 1 to 3 can be decommissioned or demolished and parts used to maintain Units 4 to 6, minimizing further capital expenditure on these units Plant Layout Figure 5-1 is an aerial photograph of the Burrard TGS site. The LMS 100 options all address adding the SCGTs at the right end (nominally the east end) of the plant where there appears to be adequate space to install several units without disrupting plant operations and provides the potential for a relatively easy change-out to the existing switchyard. It does require significant rock removal in the area, but the encroachment on the SCR ammonia storage area should not 16 May 2008 RP Revision 0 Page 11 Page 17 of 215

18 be an issue. The facilities could be indoors, but in optimizing putting the units in outdoor compartments may be preferred for Burrard TGS. An alternative siting would be at the left or west end of the plant, but this involves issues with high water lines, land ownership, moving facilities, eliminating employee parking areas, and major changes to switchyard connections. Concept 1: Figures 5-2 and 5-3 provide a site and equipment close-up conceptual layout placing three LMS 100 SCGT generators at the east end of the plant. It will require significant excavation of the area to the east of the existing Unit 1 towards the ammonia storage area, as well as an extension of the transformer area. It will, however, line up reasonably well with the existing switchyard and require modest changes to ongoing operations of the existing facility. Figure 5-1 Burrard TGS Site Aerial Photograph Concept 2: Figures 5-4 and 5-5 provide a site and equipment close-up conceptual layout placing four LMS 100 SCGT generators at the east end of the plant. It will require significant excavation of the area to the east of the existing Unit 1 towards the ammonia storage area, as 16 May 2008 RP Revision 0 Page 12 Page 18 of 215

19 well as an extension of the transformer area. It will, however, line up reasonably well with the existing switchyard and require modest changes to ongoing operations of the existing facility. Construction and maintenance logistics may be the major challenge to adding the fourth unit in the manner shown in Figure 5-5. More detailed analyses in later studies would be required. An alternative would be to put them more in line and further east. It is evident that the extent of the excavation from the existing rock faces will be significant and that an even larger rock cut may be needed to accommodate construction logistics, but that will require detailed study. It is also likely given its closeness to the existing structure and the elevated switchyard and SCR ammonia storage area that the stacks of these SCGTs will have to be taller than the 16 to 20 meters typically used. Some early changes will also be needed to the existing natural gas, steam and ammonia supply lines that pass through or near the SCGT areas early in the project schedule. This could occur during a relatively short station outage for tie-ins during a summer outage period. In order to implement either concept, the following items are required: Civil: New: Stacks; gas turbine buildings (option); main transformer enclosures; GT air intake; natural gas compression building; Modified: Switchyard reconfiguration (out of scope); Demolition: SCR ammonia enclosure rock; Mechanical: New: Modified: Gas turbines and auxiliaries; SCR and auxiliaries and piping; natural gas, steam and ammonia lines to existing units Cooling water system to LMS 100 intercoolers Electrical: New: Modified: Main Output transformers; Units station service transformers; HV switchgear; motor control centers (MCC) and cabling Existing MCC and switchgear; switchyard reconfiguration Instrumentation and Control: New: New central distributed control system (DCS) GTs, HRSG and auxiliaries Modified: Existing steam turbine DCS These LMS 100 configurations are different from that in the Task 3 report which had two of the units occupying the space of Units 1 and 2 boilers after their demolition. In this new configuration, they also occupy more space because the duct to stack length is longer to accommodate the NOx and CO SCR that are now included in the current layout drawing. 16 May 2008 RP Revision 0 Page 13 Page 19 of 215

20 Figure 5-2 Scenario A1-1 3 x LMS 100 SCGT Site Layout 16 May 2008 RP Revision 0 Page 14 Page 20 of 215

21 Figure 5-3 Scenario A1-1 3 x LMS 100 SCGT Equipment Layout 16 May 2008 RP Revision 0 Page 15 Page 21 of 215

22 Figure 5-4 Scenario A1-2 4 x LMS 100 SCGT Site Layout 16 May 2008 RP Revision 0 Page 16 Page 22 of 215

23 Figure 5-5 Scenario A1-2 4 x LMS 100 SCGT Equipment Layout 16 May 2008 RP Revision 0 Page 17 Page 23 of 215

24 5.4. Schedule The schedule, shown in Figure 5-6, for three LMS 100 SCGT installations applies well to either three or four LMS 100 SCGT. The first unit in-service would currently be in Q1 of 2014 and the last (3 rd or 4 th ) unit could be placed into service in Q2 or Q This is based on a two year SCGT order to In-Service timeline. The order placement date is Q1 2012, based on BC Hydro project and environmental approvals timeline direction. Figure 5-6 Schedule 5.5. Capital Cost The capital cost estimates for both the three LMS 100 SCGT and the four LMS 100 SCGT concepts are presented in Table 5-1. They are based on a review against a recent US LMS 100 estimate, and Ontario lump sum, turnkey, EPC SCGT and CCGT heavy frame plant estimates, with adjustments for scope differences, price increases and existing facilities at Burrard TGS. There have been considerable increases in prices in major equipment, construction labour, and commodity materials recently. Prices tend to be substantially higher than historic levels. The lump sum EPC pricing basis also tends to result in higher direct and indirect costs (but lower contingency and more certainty) than built up time and material based open book proposed costs. The estimates are somewhat higher, but reasonable compared to other recent built up estimates for similar sized conceptual brownfield plants for BC Hydro and others, recognizing that one generally pays this estimate includes high temperature SCR and has a modest premium for a fixed price lump sum contract. Based on this, the estimates appear reasonable and likely to be + 30%/-15%. The capital costs are slightly lower those in the Task 3 report as costs for existing unit asbestos removal have been removed, an increase in additional rock excavation costs, and some reduction in indirect cost rates. 16 May 2008 RP Revision 0 Page 18 Page 24 of 215

25 Table 5-2 presents the timeline assumed and a reasonable associated cashflow for analyses purposes. There is considerable room for variation in the cashflow depending on market and contracting approaches. Table 5-1 Capital Cost 3 and 4 x LMS 100 SCGT 16 May 2008 RP Revision 0 Page 19 Page 25 of 215

26 Table 5-2 Timeline and Cashflow 3 and 4 x LMS 100 SCGT 5.6. OMA Cost Indicative major planned maintenance costs for the LMS 100 SCGT cases are illustrated in Table 5-3. They must be recognized however as being very preliminary as there is limited experience on this equipment to date and limited experience with LMS 100 vendor service agreements. A Customer Service Agreement (CSA) or Long Term Service Agreement (LTSA) with an OEM is assumed to be in effect. Expected Maintenance of the LMS100 gas turbine engine follows a 50,000-hour cycle (about six years for base load operations with 8,760 operating hours per year). Preventative maintenance for the engine primarily consists of regularly scheduled borescope and package inspections. After 25,000 hours of operation (three years at base load), the hot section and combustor will need to be refurbished. After 50,000 hours (six years at base load), the entire engine will need to be overhauled. Frequent starts and stops do not generally affect repair or overhaul intervals. Preventative maintenance work can be performed by trained plant operators either independently or in conjunction with GE Aero Energy technicians under a maintenance contract. Major maintenance will be performed by personnel from an authorized depot. Scheduled maintenance events from inspections to overhauls can be completed with minimum downtime, usually on weekends or other low demand periods (usually 1-5 days; assuming a lease or exchange engine is used during overhaul). 16 May 2008 RP Revision 0 Page 20 Page 26 of 215

27 The estimates assume that the plant joins General Electric s lease engine program for use during major maintenance events. For scheduled maintenance, a lease engine can be on-site prior to shutdown and the lease engine change out can be accomplished in 24 to 48 hours. For unscheduled engine change outs, a lease engine can be delivered within 72 hours. The price of the optional lease engine program is divided into an annual fee and weekly usage charges. Based on some initial GE information, the conceptual planned maintenance costs for the program from GE (in Year 2007 Cdn$) for the 3 LMS100 machines are: Table 5-3 Maintenance Costs Scenario A1-3 Aeroderivative LMS100 Class SCGT Element Price ( 000$/yr) Peaking Intermed Base (27% ACF) (53% ACF) (95% ACF) Preventative Maintenance $100 $150 $200 Hot Section Refurbishment (at 25,000 Hrs) $750 $1,500 $2,700 Engine Overhaul (at 50,000 Hrs) $1,200 $2,300 $4,200 Optional Lease Engine Annual Fee $1,500 $1,500 $1,500 Total $3,550 $5,450 $8,600 Expressed as fixed and variable costs these costs would be approximately: Fixed costs $/kw/year $5.3/kW/Yr Variable costs $/MWh - $2.7/MWh After-market parts and third party maintenance contractors are not practical alternatives at this stage of the LMS 100 s development. One might choose to opt out of the lease engine program for a peaking facility, but for any subsequent lease engine needed the costs would increase significantly and the timeframes to deliver and swap a lease engine would increase significantly. For this analysis, the status of the technology a conservative approach was adopted. The above costs are only for planned maintenance costs for the engine itself. There would be other costs for the rest of the facility and major items such as the generator and transformers. There would also be costs for major unplanned maintenance such as equipment failures. It is assumed that 5 incremental staff are required beyond those for the remaining operational Burrard TGS Units. In some classic stand-alone SCGT plants, 5 to 10 staff are used, with management as a satellite facility provided by another location. No initial unit start-up power was charged to the facility although that is often done. There are charges added for head office and administrative support costs that may not in fact always be incremental. The LMS 100 SCGT OMA assumes the owner has a Customer Service Agreement (CSA) or Long Term Service Agreement (LTSA) with an OEM although the exact nature of that service agreement in terms of specific coverages and term is generally still evolving. The costs assume 16 May 2008 RP Revision 0 Page 21 Page 27 of 215

28 those identified in Table 5-3 are in effect to mitigate planned maintenance events. A further allowance for unplanned major maintenance is added to account for events likely to occur over the course of the life of the installation. Care must be taken in applying these costs as they (in absolute $ terms or in Fixed and Variable Cost terms) can vary significantly for peaking cases depending on specific circumstances and arrangements Environment This section will address the environmental emissions associated with the LMS100 SCGT facility and it s compatibility with existing and likely future new generation permits Air Environment Single Unit Management: Typical air emission rates of one LMS 100 SCGT unit on a stand alone basis (or multiple units in parallel) at various percentages of a unit s Maximum Continuous Rating (MCR) at International Organization for Standardization (ISO) standard conditions (59 o F, psia, 60% relative humidity (RH)) are presented in Table 5-4. Table 5-4 Single Unit LMS 100 SCGT Emissions with Load Unburnt hydrocarbons (UHC) are used in the analyses as a Particulate Matter (PM) surrogate. This represents an extreme that is not usually experienced. Large machines typically have a significant transition in NOx and CO and UHC at around the 50% to 65% MCR load point. These Dry Low NO x (DLN) Burner systems switch over from or to a second diffusion burner system to maintain a stable flame which is higher in NO x emissions. The specifics depend on the vendor and on continuing improvements. The way in which one manages the output of the multiple SCGTs can have an effect on overall emissions. The single unit emissions curves (or three units acting in parallel) are presented in Figure 5-7 (NO x, UHC, SO 2, NH 3, CO, and CO 2 ). 16 May 2008 RP Revision 0 Page 22 Page 28 of 215

29 Figure 5-7 Scenario A1 Single LMS 100 SCGT or Parallel Unit Emissions vs. Load Multi-Unit Load Management: For three or four LMS 100 SCGT units, load reduction and turning on or off individual units are part of load management. Table 5-5 presents the results at ISO conditions based on an optimum of a variety of operating patterns for a three LMS 100 SCGT case. A four unit case would be somewhat different, but similar enough for this report. Table 5-5 Multi- LMS 100 SCGT Unit Load Management - Emissions vs. Load 16 May 2008 RP Revision 0 Page 23 Page 29 of 215

30 These emissions rates are based on the volumetric emission rates presented in Table 5-6. Table 5-6 Scenario A1 Multi-Unit Load Management PPM Emissions vs. Load Figure 5-8 (NO x, UHC, SO 2, NH 3, CO CO 2 ) shows the trend of the emission factors possible if one is able to manage the turndown and shutdown of units effectively. 16 May 2008 RP Revision 0 Page 24 Page 30 of 215

31 Figure 5-8 Multi- LMS 100 SCGT Units - Emissions vs. Load 16 May 2008 RP Revision 0 Page 25 Page 31 of 215

32 The existing CSC units will continue to operate at current emission levels as per Figure 5-9 (NO x, UHC, SO 2, NH 3, CO) and Figure 5-10 (CO 2 ). Figure 5-9 Scenario 1 Existing Units (NO x, UHC, SO 2, NH 3, CO) Emissions vs. Load 16 May 2008 RP Revision 0 Page 26 Page 32 of 215

33 Figure 5-10 Scenario 1 Existing Units CO 2 Emissions vs. Load CO2 Emission Rate vs Net Output CO2 Emissions kg/kwhn MW net CO2 kg/kwhn Water Environment Water consumption and cooling water requirements in Scenario A1 for the SCGT units are minimal. It is substantially less than current CSC installation. There is no steam cycle requiring once through cooling and no boiler blowdown requiring demineralized water. There are very low requirements for lube oil coolers and generator coolers. If inlet evaporative coolers are used in summer to minimize ambient temperature derates, fresh water consumption may be significant, up to about 90 USGPM = 200,000 USGPD or about 0.75 MML/day if for 24 hrs, which is unlikely and still less than 5% of the allowable freshwater consumption from Lake Buntzen. For most of the year water use would be almost zero. Water injection may be used for NOx control if commercialization of Dry Low NOx Combustor technology is significantly delayed. The LMS 100 could also use demineralized water for NOx emissions control if desirable or if dry low NOx combustion technology experiences developmental delays, but the quantities are well below any limits on fresh water from Lake Buntzen (about 21% of the current per unit per day maximum allowed). 16 May 2008 RP Revision 0 Page 27 Page 33 of 215

34 The existing Effluent Permit No. PE restriction of 1.7 million cubic meters per day and an upper bound of 27 degrees Celsius does not impact the LMS 100 concepts. The LMS 100 SCGT uses cooling water for its unique gas turbine intercooler, but substantially less than that of the condenser cooling water of any existing steam turbines being replaced, less than 3% of the maximum permitted amount Other Environment Noise is another primary environmental impact will require significant effort in the given environment. The primary impact of extra effort on reducing air intake and exhaust noise will be on plant performance, costing up to 1% reduction in capacity and 1% in performance (i.e. 1% higher heat rate) Performance Heat Rate Impacts with Load: Figure 5-11 illustrates the impact of load on the current configuration of the existing Burrard TGS units, on heavy frame SCGTs, on LMS 100 SCGTs, and on CCGTs. The LMS SCGT has a better heat rate at all load levels than the existing units or heavy frame SCGTs, but worse than a CCGT. Clearly the LMS 100 SCGT units should dispatch ahead of the existing Burrard TGS units. Loading rates, reliability/availability/life expenditure, gas dispatch restrictions and other factors would need to be looked at in the overall context in system analyses to optimize accurately. Figure 5-11 SCGT, CCGT and Existing Units Heat Rate vs. Load 16 May 2008 RP Revision 0 Page 28 Page 34 of 215

35 Figure 5-12 illustrates a typical heat and mass balance for a 3 x LMS 100 (water injected burner in this case as an example). The net outputs are slightly less than the generic values used in the study, which will vary with the engine configuration and ambient conditions selected. It provides the basic information needed to understand the fuel and air inflows and the electricity generation. It also provides the new and clean heat rate defined as a Low Heating Value (LHV) heat rate. This is most often how the gas turbine industry provides heat rate or efficiency. It must, however, be converted to a Higher Heating Value (HHV) basis to use it with fuel pricing, which is usually quoted on a HHV basis. For natural gas, multiply LHV heat rate by 1.11 to get the HHV heat rate. For the efficiency, divide the LHV efficiency by 1.11 to get the HHV efficiency Figure x LMS 100 SCGT Performance Information New and Clean Note: To convert LHV to HHV, multiply by 1.11 In developing plans, one must also address the difference between new and clean and typical performance. Gas turbines tend to get fouled with contaminants from the air and as a result experience both a permanent degradation and a temporary/recoverable degradation. The temporary degradation will be recovered when the machines are washed either using on-line techniques or through periodic off-line washes. This degradation of both capacity and heat rate (i.e. increased heat rate or reduced efficiency) can be in the order of 2% or more depending on 16 May 2008 RP Revision 0 Page 29 Page 35 of 215

36 the environment. Further, there can be other factors that cause a higher than expected average MCR heat rate and lower than expected MCR capacity. Ambient temperature and relative humidity also have an effect on generation capacity and heat rate. Capacity tends to decrease with higher ambient temperature and heat rate rises slightly. Part load operation also has a significant effect on efficiency at loads below 50 to 70%. Figure 5-12a 3 x LMS100 SCGT Performance Information New and Clean Figure 5-13 Dry Low NOx Combustor SCGT Performance vs. Time of Year at Burrard TGS Burrard SCGT Performance % of Base MWn and Base Heat Rate 105.0% 104.0% 103.0% 102.0% 101.0% 100.0% 99.0% 98.0% 97.0% 96.0% 95.0% Jan Feb Mar Apr May Jun Jul Net Month Capacity MWn Aug Sep Oct Nov Dec Net Heat Rate The LMS 100 SCGT design in the computer modeling incorporates water injection for NOx control instead of dry low NOx combustors. This effectively increases capacity in summer and negates the impact of high summer ambient temperatures on output and efficiency. Figure May 2008 RP Revision 0 Page 30 Page 36 of 215

37 illustrates the impact on the output and heat rate throughout the year at Burrard TGS, as a function of average monthly ambient temperature and relative humidity (Environment Canada data for Port Moody Glenayre) on a heavy frame SCGT with dry low NOx combustors. A similar effect, somewhat less severe, would occur on an LMS 100 with dry low NOx burners. Figure 5-14 illustrates the effect on an LMS 100 with water injection for NOx control. In this case the summer generation is actually higher as more water is injected for NOx control. This may be an option that is desirable for a Burrard installation and should be studied in more depth at a later stage in a project. Figure 5-14 Water Injected LMS 100 SCGT Performance vs. Time of Year at Burrard TGS Ambient Conditions 5.9. Fuelling Cost The Base new and clean SCGT capacity (MW) and efficiency (kj/kwh on an HHV basis) at ISO conditions of 20 o C and 60%RH is nominally 100 MW (98.6 MWnet) and 9500 kj/kwh (9011 BTU/kWh). As per Figures 5-13 and 5-14, the ambient temperature will affect summer and winter capacities and heat rates and hence generation fuelling costs. Assuming an average 5% degradation and other losses allowance, the more typical average MCR heat rate value becomes 9980 kj/kwh (9,460 BTU/kWh). Assuming a $6/MMBTU (HHV) gas cost, its fuelling cost would average $57/MWhe. 16 May 2008 RP Revision 0 Page 31 Page 37 of 215

38 6. SCENARIO A1 600 GWH/YR PEAKING OPERATION 6.1. Operating Pattern BC Hydro provided an operating pattern for a typical week for the current Burrard TGS configuration of 6 steam cycle units and identified that a typical year would consist of three weeks of this pattern in the winter period for about 300 GWh of production. Further, a non-typical or dry year might occur every three or four years at roughly 1500 GWh/yr. An average of 600 GWh/yr (about 6.25 weeks) was used as the basis for planning. It was also assumed that 1 unit of the synchronous condenser was required 90% of time and a second unit 25% of time. A similar basis was used for the heavy frame SCGT Scenario A1 in the Task 3 report. The patterns used for the two sub-scenarios using LMS 100 SCGT are illustrated in Figure 6-1 and Figure 6-2. The LMS 100 SCGTs produce the majority of the power due to their higher efficiency, higher reliability, and rapid start capability. As a result, the distribution is as shown in Table 6-1. Figure 6-1 Scenario A1-1 3 x LMS 100 Plus Existing Units 3 to 6 Weekly Generation Profile 16 May 2008 RP Revision 0 Page 32 Page 38 of 215

39 Figure 6-2 Scenario A1-2 4 x LMS 100 Plus Existing Units 3 to 6 Weekly Generation Profile Table 6-1 Operating Pattern Distribution Generation GWh/Yr Scenario A1-1 Scenario A1-2 3 x LMS 100 Burrard TGS Units 3 to 6 4 x LMS 100 Burrard TGS Units 4 to % Generation 50.4% 49.6% 67.3% 32.7% Annual Capacity Factor % Operating Factor % 11.1% 5.5% 11.1% 4.8% 11.2% 9.4% 11.2% 8.8% 16 May 2008 RP Revision 0 Page 33 Page 39 of 215

40 For the conceptual purpose of this study, these models are adequate, however, a detailed system analysis might tend to favour a somewhat more blended result with more partial steam turbine use at higher loads and with some of the SCGTs providing more on-off peaking support during peak periods of days. This could reduce overall uneconomic run-time and thereby produce minimal overall emissions and gas consumption OMA Cost The LMS 100 SCGT OMA costs, and specifically the planned maintenance costs, were discussed in Section 5.6. A summary of the SCGT OMA costs for Case 1 and 2 are presented in Table 6-2. These are combined with costs of those existing Burrard units to provide the cashflow tables in Section 6-3. Table 6-2 OMA Costs 3 and 4 x LMS 100 SCGT 6.3. Cashflow Table 6-3 presents the Cashflow for Scenario A1-1, three LMS 100 SCGT and generation from existing Burrard TGS units 3 to 6. The table provides a capital and OMA cashflow (2007 Cdn$) from FY2008 through FY2028. It assumes that Units 1 through 6 (typically 25% generation from U1-3 and 75% from U4-6) operate until the SCGT units come on line in FY2014 at which time the pattern in Section 5.3 is used. The existing unit cashflow used is basically the current investment program adjusted to reflect the lower Units 3 to 6 ACF/OF after the SCGTs come on stream. This lower Unit 16 May 2008 RP Revision 0 Page 34 Page 40 of 215

41 4 to 6 OMA/capital stream is also consistent with the fact that spare equipment from Units 1 to 2 can be retained to support Units 3 to 6. Two aspects of the Task 1 and 2 and Task 3 reports were retained here: All units not replaced will be reliable service for 20 years. All units not replaced must be available for generation service (reliably) during peak periods little tolerance for failures to start, forced outages while needed; little/no unit sparing Table 6-3 Cashflow Scenario A1-1 3 x LMS 100 SCGT and Burrard Units 3 to 6 - Years 2008 to May 2008 RP Revision 0 Page 35 Page 41 of 215

42 Table 6-4 presents a similar cashflow for Case 2 Scenario A1-2, for four LMS 100 SCGT and generation from existing Burrard TGS units 4 to May 2008 RP Revision 0 Page 36 Page 42 of 215

43 Table 6-4 Cashflow Scenario A1-2 4 x LMS 100 SCGT and Burrard Units 4 to 6 - Years 2008 to May 2008 RP Revision 0 Page 37 Page 43 of 215

44 6.4. Environment Air Environment The emission rates and annual amounts for Scenario A1-1 (600 GWh, 3 x LMS 100 SCGT + Burrard TGS Units 3 to 6) are presented in Figure 6-3. Those for Scenario A1-2 (600 GWh, 4 x LMS 100 SCGT + Burrard TGS Units 4 to 6) are presented in Figure May 2008 RP Revision 0 Page 38 Page 44 of 215

45 Figure 6-3 Scenario A GWh Emission Rates and Annual Emissions 3 LMS 100 SCGT and Units 3 to 6 16 May 2008 RP Revision 0 Page 39 Page 45 of 215

46 Figure 6-4 Scenario A GWh Emission Rates and Annual Emissions 4 LMS 100 SCGT and Units 4 to 6 16 May 2008 RP Revision 0 Page 40 Page 46 of 215

47 7. SCENARIO A GWH/YR, INTERMEDIATE WITH SEASONAL BASE LOAD 7.1. Operating Pattern BC Hydro provided a monthly operating pattern for a 3000 GWh/yr case for the current Burrard TGS configuration of 6 steam cycle units that was interpreted to arrive at a comparable pattern for Units 1 to 3 and Units 4 to 6. The pattern suggested 0 generation in March through June. It was also assumed that 1 unit of the synchronous condenser was required 90% of time and a second unit 25% of time. Figure 7-1 Scenario 2 - Current Configuration Monthly Load Pattern Scenario GWh/Year MW and GWh/Mo Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Max Capacity Available MW Month of Year Cooling Water Limited Av Capacity MW BC Hydro Model: GWh/Yr =2976 BC Hydro Model GWh/Mo Cooling Water Limited GWh/Yr= 2976 Cooling Water Limited GWh/Mo AV Daily Capacity Req MW A similar monthly pattern was used for the Scenario A2-1 and A2-2 using 3 or 4 LMS 100 SCGT with 3 or 4 existing Burrard TGS Units to produce 3000 GWh. The LMS 100 SCGT, given their higher efficiency, are essentially used as the primary generation source and the existing Burrard TGS Units used for peaking. The pattern used is illustrated in Figure May 2008 RP Revision 0 Page 41 Page 47 of 215

48 Figure 7-2 Scenario A GWh/Mo - Generation by Month 3 x LMS 100 SCGT + Burrard TGS Units 3 to 6 For this concept study, this model is likely adequate. A more detailed system study is recommended to evaluate the options in more detail taking into consideration the very unique features of the BC Hydro system and resources. Actual operation may tend to favour a somewhat more blended result with more partial steam turbine use. High sustained loads on the existing steam turbines where longer sustained runs are needed, and more fast starts of one or more of the SCGT units may be desirable. 16 May 2008 RP Revision 0 Page 42 Page 48 of 215

49 Figure 7-3 Scenario A GWh/Mo - Generation by Month 4 x LMS 100 SCGT + Burrard TGS Units 3 to 6 Generation GWh/Yr Table 7-1 Operating Pattern Distribution Scenario A2-1 and A2-2 Scenario A2-1 Scenario A2-2 3 x LMS 100 Burrard TGS Units 3 to 6 4 x LMS 100 Burrard TGS Units 4 to % Generation 53.3% 46.7% 70.6% 29.4% Annual Capacity Factor % Operating Factor % 60.6% 26.3% 60.0% 22.0% 63% 36% 73% 31% 16 May 2008 RP Revision 0 Page 43 Page 49 of 215

50 7.2. OMA Cost The LMS 100 SCGT Maintenance costs were discussed in Section 5.6. A summary of the SCGT OMA costs for Scenario A2-1 and A2-2 are presented in Table 7-2. These are combined with costs of those existing Burrard units to provide the cashflow tables in Section 7-3. Table 7-2 OMA Costs Scenario A GWh/yr, 3 and 4 x LMS 100 SCGT 7.3. Cashflow Table 7-3 presents the Cashflow for Scenarios A2-1, three LMS 100 SCGT and generation from existing Burrard TGS units 3 to 6. It provides a capital and OMA cashflow (2007 Cdn$) from FY2008 through FY2028. It assumes that Units 1 through 6 (typically 25% generation from U1-3 and 75% from U4-6) operate until the SCGT units come on line in FY2014 at which time the pattern in Section 5.3 is used. The existing unit cashflow used is basically the current investment program adjusted to reflect the lower Units 3 to 6 ACF/OF after the SCGTs come on stream. This lower Unit 4 to 6 OMA/capital stream is also consistent with the fact that spare equipment from Units 1 to 2 can be retained to support Units 3 to 6. Two aspects of the Task 1 and 2 and Task 3 reports were retained here: All units not replaced will be reliable service for 20 years. 16 May 2008 RP Revision 0 Page 44 Page 50 of 215

51 All units not replaced must be available for generation service (reliably) during peak periods little tolerance for failures to start, forced outages while needed; little/no unit sparing Table 7-3 Cashflow Scenario A2-1 3 x LMS 100 SCGT and Burrard Units 3 to 6 - Years 2008 to May 2008 RP Revision 0 Page 45 Page 51 of 215

52 Table 7-4 presents a similar cashflow for Case 2 Scenario A2-2, for four LMS 100 SCGT and generation from existing Burrard TGS units 4 to May 2008 RP Revision 0 Page 46 Page 52 of 215

53 Table 7-4 Cashflow Scenario A2-2 4 x LMS 100 SCGT and Burrard Units 4 to 6 - Years 2008 to May 2008 RP Revision 0 Page 47 Page 53 of 215

54 7.4. Environment Air Environment The emission rates and annual amounts for Scenario A2-1 (3000 GWh, 3 x LMS 100 SCGT + Burrard TGS Units 3 to 6) are presented in Figure 7-3. Those for Scenario A2-2 (3000 GWh, 4 x LMS 100 SCGT + Burrard TGS Units 4 to 6) are presented in Figure May 2008 RP Revision 0 Page 48 Page 54 of 215

55 Figure 7-3 Scenario A GWh/Mo Emissions by Month 3 X LMS 100 SCGT and Burrard TGS Units 3 to 6 16 May 2008 RP Revision 0 Page 49 Page 55 of 215

56 Figure 7-4 Scenario A GWh/Mo Emissions by Month 4 X LMS 100 SCGT and Burrard TGS Units 4 to 6 16 May 2008 RP Revision 0 Page 50 Page 56 of 215

57 8. SCENARIO A GWH/YR, YEAR ROUND BASE LOAD 8.1. Operating Pattern BC Hydro provided a monthly operating pattern for a 6000 GWh/yr case for the current Burrard TGS configuration of 6 steam cycle units (Figure 8-1) The pattern suggested all six Burrard TGS units were fairly base loaded from September through February at about 60 to 75% monthly capacity factor, and that in April through September 5 units were similarly base loaded each of the six units was out of service for one month during the period for maintenance. Figure 8-1 Operating Pattern - Scenario GWh/yr, Current Configuration Scenario GWh/Year MW and GWh/Mo Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Max Capacity Available MW Cooling Water Limited Av Capacity MW BC Hydro Model GWh/Mo Cooling Water Limited GWh/Mo Actual generation GWh/Mo Month of Year BC Hydro Model: GWh/Yr =6112 Cooling Water Limited GWh/Yr= 5872 Actual Generation GWh/Yr= 5830 A similar monthly pattern was used for the Scenario A3-1 and A3-2 using three and four LMS 100 SCGT. 16 May 2008 RP Revision 0 Page 51 Page 57 of 215

58 Figure 8-2 Operating Pattern Scenario 3A GWh/yr 3 LMS 100 SCGT and Burrard TGS Units 3 to 6 16 May 2008 RP Revision 0 Page 52 Page 58 of 215

59 Figure 8-3 Operating Pattern Scenario 3A GWh/yr 4 LMS 100 SCGT and Burrard TGS Units 4 to 6 For this concept study, this model is likely adequate. A more detailed system study is recommended to evaluate the options in more detail taking into consideration the very unique features of the BC Hydro system and resources. Actual operation may tend to favour a somewhat more blended result with more partial steam turbine use. High sustained loads on the existing steam turbines where longer sustained runs are needed, and more fast starts of one or more of the SCGT units may be desirable. 16 May 2008 RP Revision 0 Page 53 Page 59 of 215

60 Generation GWh/Yr Table 8-1 Operating Pattern Distribution Scenario A3-1 Scenario A3-2 3 x LMS 100 Burrard TGS Units 3 to 6 4 x LMS 100 Burrard TGS Units 4 to % Generation 37.6% 62.4% 49.9% 50.1% Annual Capacity Factor % Operating Factor % 8.2. OMA Cost 87.6% 73.1% 87.6% 78.7% 90% 77% 90% 83% The LMS 100 SCGT Maintenance costs were discussed in Section 5.6. A summary of the SCGT OMA costs for Scenarios A3-1 and A3-2 is presented in Table 8-2. These are combined with costs of those existing Burrard units to provide the cashflow tables in Section 8-3. Table 8-2 OMA Costs 3 and 4 x LMS 100 SCGT 16 May 2008 RP Revision 0 Page 54 Page 60 of 215

61 8.3. Cashflow Table 8-3 presents the Cashflow for Scenario A3, three LMS 100 SCGT and generation from existing Burrard TGS units 3 to 6. It provides a capital and OMA cashflow (2007 Cdn$) from FY2008 through FY2028. It assumes that Units 1 through 6 (typically 50% generation from U1-3 and 50% from U4-6) operate until the SCGT units come on line in FY2014 at which time the pattern in Section 5.3 is used. The existing unit cashflow used is basically the current investment program adjusted to reflect the lower Units 3 to 6 ACF/OF after the SCGTs come on stream. This lower Unit 4 to 6 OMA/capital stream is also consistent with the fact that spare equipment from Units 1 to 2 can be retained to support Units 3 to 6. Table 8-3 Cashflow Scenario A3-1 3 x LMS 100 SCGT and Burrard Units 3 to 6 - Years 2008 to May 2008 RP Revision 0 Page 55 Page 61 of 215

62 Two aspects of the Task 1 and 2 and Task 3 reports were retained here: All units not replaced will be reliable service for 20 years. All units not replaced must be available for generation service (reliably) during peak periods little tolerance for failures to start, forced outages while needed; little/no unit sparing Table 8-4 presents a similar cashflow for Case 2 Scenario A3-2, for four LMS 100 SCGT and generation from existing Burrard TGS units 4 to May 2008 RP Revision 0 Page 56 Page 62 of 215

63 Table 8-4 Cashflow Scenario A3-2 4 x LMS 100 SCGT and Burrard Units 3 to 6 - Years 2008 to May 2008 RP Revision 0 Page 57 Page 63 of 215

64 8.4. Environment Air Environment The emission rates and annual amounts for Scenario A3-1 (6100 GWh, 3 x LMS 100 SCGT + Burrard TGS Units 3 to 6) are presented in Figure 8-3. Those for Scenario A3-2 (6100 GWh, 4 x LMS 100 SCGT + Burrard TGS Units 4 to 6) are presented in Figure May 2008 RP Revision 0 Page 58 Page 64 of 215

65 Figure 8-3 Scenario A GWh/Mo Emissions by Month 3 X LMS 100 SCGT and Burrard TGS Units 3 to 6 16 May 2008 RP Revision 0 Page 59 Page 65 of 215

66 Figure 8-4 Scenario A GWh/Mo Emissions by Month 4 X LMS 100 SCGT and Burrard TGS Units 4 to 6 16 May 2008 RP Revision 0 Page 60 Page 66 of 215

67 9. ENVIRONMENTAL PERFORMANCE OVERVIEW 9.1. Operating Pattern Table 9-1 and 9-2 present a summary comparison of annual emissions for the various Scenarios, including those in the Task 1&2 and Task 3 reports: air Emissions of all pollutants considered increase significantly with generation levels regardless of the technology employed CCGT technology in Scenarios A2 and A3 is the only technology to significantly reduce all emissions (except ammonia likely could be managed to similar levels, and perhaps particulate actual test program particulate emissions would likely be very similar) LMS 100 SCGT ( 3 or 4 units) can reduce emissions relative to the Current Configuration of existing Burrard TGS units of CO 2, NOx and SO 2 by 5% to 10% emissions o LMS 100 SCGT must have SCR to minimize NOx emissions heavy frame SCGT with dry low NOx combustors increase emissions, especially NO x emissions and likely be limited to a peaking role o Heavy frame SCGT are not readily adaptable to SCR and hence low NOx emissions Table 9-1 Scenario Emissions Comparison 16 May 2008 RP Revision 0 Page 61 Page 67 of 215

68 Table 9-2 Scenarios Emissions Comparison 16 May 2008 RP Revision 0 Page 62 Page 68 of 215

69 10. SUMMARY Burrard TGS offers a reasonable opportunity for an LMS 100 SCGT gas turbine modification, where improvements in environmental performance are required and regulatory or generation futures uncertainty makes a combined cycle impractical. Its major drawbacks are its high $/kw cost and its modest improvement in efficiency over existing Burrard TGS steam turbine units for peaking purposes and its low efficiency and hence fuelling economy compared to a combined cycle for base load generation. The major conclusions of this assessment are: 1. LMS 100 SCGT implementation of three or four units (300 to 400 MW) would likely not take place before mid 2014 at the earliest. 2. Air emissions will increase with increased generation levels, regardless of which technology is employed. The absolute value at any particular generation level is minimized by use of CCGT, followed by LMS 100 SCGT. 3. Existing Units 1 to 6 will need significant investment (spares purchases and detailed inspection and purchases as required) to ensure their high availability/reliability capability to the LMS 100 SCGT in-service dates and for Units 4 to 6 and possibly Unit 3 for the period 2014 to The LMS 100 SCGT has higher efficiencies than the existing Burrard TGS units and heavy frame SCGT and will tend to run ahead of any existing Burrard TGS units helping to extend their life and reduce their fuelling costs. 5. LMS 100 SCGT capital costs are likely between $850 and $900/kW (2007$) for a turn-key lump sum EPC contract, including high temperature SCR and CO catalyst. 6. LMS 100 SCGT have a relatively high capital cost per kw. Their higher cost justification likely depends on there being considerable regulatory and/or generation futures uncertainty. This may make a case for them versus either less efficient, less environmentally friendly heavy frame SCGT peakers or more efficient, more environmentally attractive, base loaded CCGT that may also be difficult to permit due to their high absolute emissions (due to higher generation levels). 7. Current air emission of effluent permit limits for Burrard TGS should not be a significant issue with LMS 100 SCGT applications. BACT measures in PSD areas of the United States could be applied. Some special measures to manage particulate matter and ammonia emissions within existing Burrard TGS permit criteria (g/m 3 ) may be needed. Measures to minimize noise to the local environment may be adopted, but will tend to have modest negative impacts on SCGT and CCGT performance (capacity, efficiency). 8. A staged approach to implementation (two LMS 100 followed later by a further one or two) might be considered as part of a system optimization. 9. A detailed system analyses is required to determine optimal technology selection, particularly given the particular system resources, demands and constraints in the BC Hydro system, its inter-connected neighbours, and fuel supply systems. 16 May 2008 RP Revision 0 Page 63 Page 69 of 215

70 Appendix 1 GLOSSARY 16 May 2008 RP Revision 0 Page 64 Page 70 of 215

71 o F or of o C or oc $MM a AC ACF ASME Av or AV BC BACT BGS BTGS BTU BFP BUP C1 CA CAP CCGT CEA CEM CFM CO 2 or CO2 CO CO/CB CP cps CSC CW DC DCS FD FY g G G1 GEN Gg GJ GT GVA GVRD GW GWh h or hr or hrs H2 or H 2 HP HRSG degree Fahrenheit degree Celsius millions of $ annum (see also year) alternating current annual capacity factor = (actual MWh/yr)/(MCR x 8760) American Society of Mechanical Engineers average British Columbia Best Available Control Technology Burrard Generating Station British Thermal Unit boiler feed pump Burrard Upgrade Project base capital item for a Scenario availability capital investments (i.e. spares) to ensure avail. capital combined cycle gas turbine Canadian Electricity Association continuous emission monitor cubic feet per minute carbon dioxide carbon monoxide corrective/condition based maintenance probability capital investments (i.e. replacements expected) cycles per second or Hertz conventional steam cycle circulating or cooling water direct current distributed control system forced draft fiscal year gram gauge generating unit #1 generating (as in hours generating see SC) gigagrams gigajoules gas turbine Greater Vancouver Regional District Greater Vancouver Area gigawatts (1000 MW) gigawatthours (1000 MWh) hours hydrogen horsepower heat recovery steam generator 16 May 2008 RP Revision 0 Page 65 Page 71 of 215

72 Hz HHV in or ID IG IGPM IP ISO k$ kg kv kva kvar kw kwh L LP LHV m3 or m 3 M$ Max MCC MCR mm Mo Mg mg MOT Mtce MVA MVAR MW/MWg/MWn MWh/MWhg/MWhn Hg Min N+0, where N=x N+2, where N=x NBC NDE/NDT NH3 or NH 3 NiCrMoV NO2 or NO 2 NO NOx or NO x O2 or O 2 OD OEM OF hertz higher heating value inches induced draft imperial gallons imperial gallons per minute intermediate pressure International Organization for Standardization thousands of $ kilograms kilovolt kilovolt ampere kilovolt ampere reactive kilowatt kilowatthour liter low pressure lower heating value cubic metres millions of $ maximum motor control centre maximum continuous rating (MW) could be gross or net millimeter month megagrams milligrams main output transformer maintenance megavoltampere megavolt ampere reactive megawatt /megawatt gross/megawatt net megawatt hour/ megawatthour gross/megawatthour net mercury minute plant with x+0 units and all are needed (0 spares) plant with x+2 units and x are needed (2 spares) National Building Code non destructive evaluation/testing ammonia nickel/chromium/molybdenum/vanadium nitrogen dioxide nitric oxide oxides of nitrogen oxygen outside diameter original equipment manufacturer operating factor = (hrs unit operates per year)/(8760hrs per yr) 16 May 2008 RP Revision 0 Page 66 Page 72 of 215

73 OMA or OM Ops PCB ph PM PM2.5 PM psig or psi g psia or psi a ppmvd or ppm vd % RH rpm s or sec SC scfh SCGT SCR SH SO2 or SO 2 Sq ft or SF SST ST STG T7 TGS TSI TWh TWIPS U1 UK VAR V WTP yds Yr (or a) operations, maintenance and administration (at plant) operations polychlorinated biphenyls a measure of acidity particulate matter particulate matter (less than 2.5 microns in diameter) preventative maintenance pound per hour pounds per square inch gauge pounds per square inch absolute parts per million (dry volume basis) percentage reheat revolutions per minute second synchronous condenser standard cubic feet per hour simple cycle gas turbine sulphur dioxide super heat selective catalytic reduction square feet station service transformer steam turbine steam turbine generator transformer #7 thermal generating Station Thermal Subject Index Terawatthours (1,000,000 MWh) turbine water induction prevention system Unit #1 United Kingdom vars volts water treatment plant yards year 16 May 2008 RP Revision 0 Page 67 Page 73 of 215

74 28 April 2008 RP Revision 1 Page 74 of 215

75 28 April 2008 Mr. Tom Coyle Mr. Craig Godsoe Director, Major Capital Projects Solicitor & Counsel British Columbia Hydro British Columbia Hydro 6911 Southpoint Dr., 17th floor Dunsmuir Street Burnaby, BC V3N 4X8 Vancouver, BC V6B 5R3 Canada Canada Dear Tom and Craig, (TGS) Alternative Configuration Study Task 3 Final Report As per our Agreement and recent discussions, we have completed the Task 3 Alternative Configuration Final Report. Task 3: A report documenting a reasonable view of Alternative Configuration for a Repowered Burrard TGS including recommended capital, and OMA cost estimates and a report documenting recommended maintenance cost estimates for the three BC Hydro operating scenarios for life to 2028 I trust that the report satisfies your needs based on our scope and discussions over the last couple of months. Thank you for the opportunity to work on this very interesting project. Yours truly, Blair Seckington Director, Power Technology Direct Tel.: Direct Fax: blair.seckington@amec.com BRS/brs c: R. Livet AMEC Americas Limited 2020 Winston Park Drive Suite 700 Oakville, Ontario Canada L6H 6X7 Tel (905) Fax (905) Page 75 of 215

76 CONDITION ASSESSMENT AND ALTERNATIVE CONFIGURATION STUDY BURRARD TGS April 28, 2008 BURRARD TGS ALTERNATIVE CONFIGURATION Task 3 Alternative Configuration Blair Seckington 28 April 2008 Prepared by: Date Dr Nat Natarajan 28 April 2008 Checked by: Date Bob Livet 28 April 2008 Approved by: Date Rev. Description Prepared By: Checked: Approved Date A Draft Report B Seckington N. Natarajan R Livet 15Feb08 B Final report B. Seckington N. Natarajan R. Livet 27Mar08 0 Final report (Not issued) B. Seckington N. Natarajan R. Livet 18Apr08 1 Final report B. Seckington N. Natarajan R. Livet 28Apr08 28 April 2008 RP Revision 1 Page 76 of 215

77 IMPORTANT NOTICE This report was prepared exclusively for BC Hydro by AMEC Americas Limited. The quality of information, conclusions and estimates contained herein is consistent with the level of effort involved in AMEC Americas Limited services and based on: i) information available at the time of preparation; ii) data supplied by outside sources; and iii) the assumptions, conditions, and qualifications set forth in this report. This report is intended to be used by BC Hydro only, including as support for BC Hydro s regulatory filings with the British Columbia Utilities Commission (BCUC), subject to the terms and conditions of its contract with AMEC Americas Limited. Any other use of, or reliance on, this report by any third party for purposes unrelated to BC Hydro s regulatory proceedings before the BCUC is at that party s sole risk. 28 April 2008 RP Revision 1 Page 77 of 215

78 EXECUTIVE SUMMARY TASK 3 ALTERNATIVE CONFIGURATION Introduction: (Burrard TGS) is a six unit, 900 MW, natural gas fuelled, steam cycle fossil generating station located near Port Moody on Burrard Inlet. Its six 150 MW units were placed in-service by BC Hydro between 1964 and Burrard TGS has operated in many modes since it s in-service from base load to intermediate to peaking to peaking and synchronous condenser operation. Since 2002, it has primarily had 3 units operating as peaking capacity on the order of 200 GWh/year and three units operating as synchronous condensers (with the balance of their equipment mothballed). In 2007 and through 2008, the process to return the three synchronous condensing units to generating service, primarily as peaking insurance, was started. The role of the station may be even more significant as indicated by the three Alternative Configuration scenarios selected for this study for an extended plant life to 2028 using simple cycle gas turbine (SCGT) and combined cycle gas turbine (CCGT) generation concepts: replace Burrard TGS units with equivalent peaking capacity-only SCGT generation facility replace Burrard TGS units with CCGT generation to meet both capacity and some energy requirement with target of 3000 GWh/yr replace current Burrard TGS generation configuration with CCGT generation to meet both capacity and base load energy with target of 6100 GWh/yr It was subsequently agreed with BC Hydro that these configurations would be modified to: Scenario A1: Scenario A2: Scenario A3: 600 GWh/yr - install SCGT units to displace approximately half of the six existing Burrard TGS units to provide 600 GWh/yr of winter peaking generation (Average 600 GWh/yr; Range of 200 to 1500 GWh/yr) 3000 GWh/yr install a nominally 540 MW CCGT unit to displace approximately half of the six existing Burrard TGS units to provide 3000 GWh/yr of intermediate capacity providing seasonal base load and intermediate generation, with little or no summer generation 6000 GWh/yr install two nominally 540 MW CCGT units to displace all six existing Burrard TGS units to provide 6000 GWh/yr of year round base load generation The key issues addressed in this report are: The layouts and installation costs of each Scenario The potential in-service dates of the Alternative Configurations 28 April 2008 RP Revision 1 Page S1 Page 78 of 215

79 The cashflows, including those of the existing units to continue through to and in some cases beyond the in-service dates of the new SCGT and CCGT units The environmental performance of the new SCGT and CCGT units. AMEC undertook an analysis of permitting requirements for the three Alternative Configuration Scenarios for the purpose of providing the environmental performance information. AMEC did not undertake an analysis of all of the environmental assessment, permitting and other regulatory approval requirements applicable to the Alternative Configurations. Scenario A1: 600 GWh/yr, 514 MW SCGT plus Existing Units 4 to 6 The Scenario A1 layout is illustrated in Figure ES-1. It features three heavy frame F Class SCGT units added to the east end of the existing plant, just east of existing Unit 1. These would displace existing Units 1 to 3, while Units 4 to 6 would continue to be used. More detail is in the report body. Figure ES-1 Scenario A1 600 GWh/yr, 514 MW SCGT Burrard TGS Location 28 April 2008 RP Revision 1 Page S2 Page 79 of 215

80 The capital cost cashflow in Figure ES-2 provides both the bottom line capital cost (2007$ with no interest) and a conceptual timeline and cashflow. This assumes that no decision is taken until the fall of 2008 to proceed and it takes a further one year of consultation followed by a three year environmental assessment and permitting process and a two year implementation and construction period. Figure ES-2 Scenario A1 600 GWh/yr, 514 MW SCGT Capital Cashflow Once installed it assumes that the SCGT units run preferentially to the existing Units 4 to 6. In this way they generate the majority of the 600 GWh/yr. The details of the Operating Pattern and assumptions are in the body of the report. This may not be the way that these units ultimately would operate, but it provides a reasonable starting point for more detailed system analyses by BC Hydro. Figure ES-3 provides an overview of the 20 Year Cashflow for the existing Units 1 to 6 up to the inservice date of the SCGT units, plus the SCGT units and Units 4 to 6 from that point forward to 2028 (Fiscal year 2028). It does assume that significant expenditures are made on Units 1 to 6 to maintain a high availability as required by BC Hydro, similar to that of Scenario 1 in Tasks 1 and 2 28 April 2008 RP Revision 1 Page S3 Page 80 of 215

81 of this study. It does, however, recognize that the need for Units 1 to 3 is only until 2014 and there will be spare equipment available for Units 4 to 6 from Units 1 to 3 at that time. Figure ES-3 Scenario A1 600 GWh/yr, 514 MW SCGT 20 Year Cashflow The heavy frame SCGTs are environmentally less attractive than the existing Burrard TGS units, except that they require substantially less cooling water or fresh water make-up. Their full load efficiency is similar to the existing units at full load, but significantly worse at part loads (See Figure ES-4). The SCGT oxides of nitrogen (NO x ) emissions are significantly higher when compared on a gram per kwh basis. Best Available Control Technology 1 (BACT) for SCGTs in almost all jurisdictions is 1 BACT is a pollution control standard mandated by the U.S. Environmental Protection Agency (U.S. EPA). The U.S. EPA determines what air pollution control technology will be used to control a specific pollutant to a specific limit. When a BACT is determined, factors such as energy consumption, regional environmental impact and economic costs are taken into account. The BACT standard, which is significantly more stringent than the Reasonably Available Control Technology standard, has been imported into Canada for permitting purposes. 28 April 2008 RP Revision 1 Page S4 Page 81 of 215

82 Dry Low NO x Burners (DLN). DLN typically achieves <9 parts per million (ppm) (at 15% oxygen (O 2 )). This is comparable to about 24 to 27 ppm (at 3% O 2 ) on conventional steam cycle (CSC) units such as the existing Burrard TGS units. The Burrard TGS units have Selective Catalytic Reduction (SCR) 2 units on the back end and are limited to 17 ppm at loads greater than about 42 MW. This is lower than the heavy frame SCGT, although the existing Burrard TGS unit SCRs result in ammonia slip, the release of up to 10 ppm of ammonia (NH 3 ) which can contribute to downstream fine particulate matter (PM) formation. Ammonia slip is not an issue for the heavy frame SCGT without SCR. Figure ES-4 Scenario A1 600 GWh/yr, 514 MW SCGT Efficiency Comparison SCGT and Existing Units Net Ht Rate GJ/MWhn Scenario A1-600 GWh/Yr SCGT Unit Heat Rate vs % MCR Load 0% 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100 % % of MCR SCGT Units 4 to 6 Figure ES-5 and Figure ES-6 show the environmental emissions rates (per day and annual) for Scenario 1 for the Current Configuration with the existing units only and Scenario A1 with the SCGT and Units 4 to 6. Assuming that running the SCGT units at full load would result in the existing CSC units running at part loads more often, then the combined operation would have higher emissions per kwh. The result is a significant increase in air emissions, including carbon dioxide (CO 2 ), a greenhouse gas. 2 In many jurisdictions SCR is considered to be BACT for reducing NOx emissions from CCGT and in some is beginning to be considered BACT for SCGT, primarily smaller aeroderivative gas turbines. 28 April 2008 RP Revision 1 Page S5 Page 82 of 215

83 Figure ES-5 Scenario GWh/yr, Current Configuration Air Emissions 28 April 2008 RP Revision 1 Page S6 Page 83 of 215

84 The SCGTs do provide rapid response (fast start and stop), but this is less significant in a high percentage hydro system with plenty of energy storage capability. Given the relative shape of the efficiency curves, it is likely that neither the SCGTs nor the CSC existing units would dominate, but rather some blending of operation would occur to optimize the combination of technologies. Figure ES-6 Scenario A1 600 GWh/yr, 514 MW SCGT Plus Units 4 to 6 Air Emissions SCGT Units Plus Units 4 to 6 28 April 2008 RP Revision 1 Page S7 Page 84 of 215

85 Given the potential challenges of permitting an SCGT without SCR in the Greater Vancouver Regional District, AMEC also reviewed aeroderivative SCGTs as an option to the heavy frame SCGT. Aeroderivative SCGTs may be able to use a high temperature catalyst SCR on the exhaust gases, even in a simple cycle configuration. Aeroderivative SCGT have a lower exhaust flue gas temperature that when combined with a higher efficiency (37-40%) versus the heavy frame SCGT (32-35%) would reduce NO x emission well below those of the existing CSC units. Conventional lower temperature catalyst SCR might also be applied to either heavy frame SCGT or aeroderivative SCGT if the hot flue gas is diluted and cooled with excess air before the SCR. This is more expensive and has impacts of unit efficiency and unit space/footprint requirements. It is the only approach plausible if heavy frame SCGT SCR is required. The aeroderivative SCGTs are significantly higher in capital cost, but may recoup that in fuel savings if run often. Some information is included herein, but it will be examined in more detail in a supplemental report. Scenario A2: 3000 GWh/yr, 540 MW CCGT plus Existing Units 4 to 6 The layout proposed is illustrated in Figure ES-7. It features two heavy frame F Class gas turbines and two Heat Recovery Steam Generators (HRSG) added to the east end of the existing plant, just Figure ES-7 Scenario A GWh/yr, 540 MW CCGT Burrard TGS Location 28 April 2008 RP Revision 1 Page S8 Page 85 of 215

86 east of existing Unit 1, as well as a new steam turbine retrofitted in the space of the Unit 1 steam turbine designed for combined cycle service. The unit would displace existing Units 1 to 3, while Units 4 to 6 would continue to be used. More detailed figures are included in the report body. The capital cost cashflow in Figure ES-8 provides both the bottom line capital cost (2007$ with no interest) and the timeline. This assumes that no decision is taken until the fall of 2008 to proceed, and it takes a further one year of consultation followed by a three year environmental assessment and permitting process and a three year implementation and construction period. It is based on a fairly conservative lump sum, Engineering Procurement Construction (EPC) approach to construction. It would require rock excavation at the east end of the plant. There are several options and aspects that could be pursued that could influence overall design and performance. Figure ES-8 Scenario A GWh/yr, 540 MW CCGT Capital Cashflow 28 April 2008 RP Revision 1 Page S9 Page 86 of 215

87 Once installed it is assumed that the CCGT units run preferentially to the existing Units 4 to 6 due to their higher efficiency and lower emissions. In this way they generate the majority of the 3000 GWh/yr. The details of the Operating Pattern and assumptions are in the body of the report. Clearly, the actual operation would differ from this, being subject to a variety of constraints and issues outside of the performance of the units. Figure ES-9 and 9a provides an overview of the 20 Year Cashflow for both the existing Units 1 to 6 up to the in-service date of the CCGT unit, plus the CCGT units and Units 4 to 6 costs from that point forward to 2028 (Fiscal year 2028). As with Scenario 2 in Task 1 and 2 of the study, there is significant expenditure required on Units 1 to 6 to maintain their capacity availability very high as requested by BC Hydro. The costs are somewhat tempered by the fact that the CCGT unit would come into service in late Costs for Units 4 to 6 reflect that their life continues to 2028, and the units must be dependable even though operated at fairly low generation levels. The heavy frame CCGTs are much more environmentally attractive than the existing CSC units. They also require only about 40% of the cooling water and fresh water per MWh of production. The CCGTs efficiency is significantly better than the existing units at all loads (See Figure ES-10). This has benefits on all emissions, but particularly for CO 2. The CCGT NO x emissions on a gram per kwh basis are also significantly lower because it uses BACT. BACT for CCGT in many jurisdictions is between 2 to 5 ppm (at 15% O 2 ). Some still use Dry Low NO x Burners (DLN) which can achieve <9 ppm (at 15% O 2 ), while others use a regular burner producing up to 25 ppm NOx (at 15% O 2 ) plus an SCR to get to the 2 to 5 ppm (at 15% O 2 ) target. This is comparable to about 4 to 9 ppm (at 3% O 2 ) on a CSC unit such as the existing Burrard TGS units. By comparison, Burrard TGS with their SCR units on the exhaust end are limited to 17 ppm, but can achieve somewhat lower than 17 ppm. The CCGT with an SCR also emits ammonia, restricted to 5 ppm (at 15% O 2 ) at the end of its catalyst life (much less when nearly new). Similarly, the existing Burrard TGS unit SCR emits up to 10 ppm (at 3% O 2 ) of ammonia, equivalent to about 5 ppm (at 15% O 2 ) on a CCGT. Ammonia can contribute to downstream PM formation. 28 April 2008 RP Revision 1 Page S10 Page 87 of 215

88 Figure ES-9 Scenario A GWh/yr, 540 MW CCGT 20 Year Cashflow 28 April 2008 RP Revision 1 Page S11 Page 88 of 215

89 Figure ES-9a Scenario A GWh/yr, 540 MW CCGT 20 Year Cashflow ( ) 28 April 2008 RP Revision 1 Page S12 Page 89 of 215

90 15.00 Figure ES-10 Scenario A GWh/yr, 540 MW CCGT Efficiency Comparison CCGT and Existing Units Scenario A GWh/Yr CCGT Unit Heat Rate vs % MCR Load Net Ht Rate GJ/MWhn % 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100% % of MCR CCGT Units 4 to 6 Figure ES-11 and Figure ES-12 show the environmental emissions rates (per month and annual) for Scenario 2 for the Current Configuration with the existing units only and Scenario A2 with the CCGT and Units 4 to 6. Running the CCGT units at full load would result in the existing CSC running at part loads more and hence typically at higher emissions per kwh. That result would be, however, completely offset by the lower emissions of the CCGT, including CO 2. The CCGT has a more rapid response (faster start and stop), but this is less significant in a high percentage hydro system with plenty of energy storage capability. As with the SCGTs, there may be a period during CCGT start-up where low NO x burner systems are in transition and NO x emissions are higher. During this start-up period, which can be up to 2 hours during a cold start, the NO 2 component of the NO x may be visible as a brown plume. Control systems are available in some cases to minimize the brown plume s duration, but it generally can t be prevented. The spike typically occurs before the gas turbine reaches a load where the low NOx combustion systems can be applied without impacting combustion stability and the SCR can be effective. The duration and degree of the spike depends on the machine type, the gas turbine combustor type, and the use of combustion optimization techniques that may be applied. 28 April 2008 RP Revision 1 Page S13 Page 90 of 215

91 Figure ES-11 Scenario GWh/yr, Current Configuration Air Emissions 28 April 2008 RP Revision 1 Page S14 Page 91 of 215

92 Figure ES-12 Scenario A GWh/yr, 540 MW CCGT Air Emissions CCGT Units Aeroderivative CCGTs are not usually an option for large CCGT, since they suffer from lower overall efficiency as a combined cycle and have no emissions advantage versus the heavy frame. An aeroderivative SCGT may, however, be considered as an alternative to CCGT where the annual capacity factors are likely to be fairly low. It might also be considered in repowering an existing 28 April 2008 RP Revision 1 Page S15 Page 92 of 215

93 steam turbine. A aeroderivative SCGT run at higher annual capacity factors will be examined in a supplemental report. Scenario A3: 6000 GWh/yr, 1100 MW CCGT The layout proposed is illustrated in Figure ES-13. It features two CCGT units. Each unit consists of two heavy frame F Class gas turbines and two HRSGs as well as a new steam turbine. Two gas turbines and HRSGs are added to the east end of the existing plant with two others in the space of the existing Units 2 and 3 steam turbines and boilers. The new steam turbines would be retrofitted in the space of current steam turbines 1 and 4. The units would eventually displace all of the existing Burrard TGS Units 1 to 6. Units 2 to 4 would run until the first CCGT unit is complete or demolition/construction starts on the second CCGT. More detailed figures are included in the report body. The capital cost cashflow in Figure ES-14 provides both the bottom line capital cost (2007$ with no interest) and the timeline. The second CCGT unit is expected to cost considerably more to install due to the demolition and construction taking place between two operating units - the first CCGT at the east end of the plant and Units 4 to 6 in the west. It may not in fact be an acceptable option. It could be placed at the west end of the site, but site issues there may make a second CCGT unit undesirable for Burrard TGS. It is assumed that no decision is taken to proceed until the fall of 2008 and it takes a further one year of consultation followed by a three year environmental assessment and permitting process and a three year implementation and construction period, plus an additional year for the second CCGT unit. When the first CCGT is installed, it should produce the majority of the power as in Scenario A2. Once both CCGT units are installed, they should split the load fairly evenly. The load pattern is year round base load. The one issue will be those years where a steam turbine is taken out of service for overhaul which will also take out the two associated gas turbines unless they have been equipped with bypass stacks (unlikely). This will need to be done at a time of low load. The details of the operating pattern and assumptions are in the body of the report. Figures ES-15 and ES-15a provide an overview of the 20 Year cashflow for both the existing Burrard TGS Units 1 to 6 up to the in-service date of the CCGT units, plus the CCGT units from that point forward to 2028 (Fiscal year 2028). The transition years in 2014 and 2015 will, of course, require some more detailed analyses to ensure that any final design does not compromise the site s capacity and energy generation capability in those years. 28 April 2008 RP Revision 1 Page S16 Page 93 of 215

94 Figure ES-13 Scenario A GWh/yr, 1100 MW CCGT Burrard TGS Location 28 April 2008 RP Revision 1 Page S17 Page 94 of 215

95 Figure ES-14 Scenario A GWh/yr, 1100 MW CCGT Capital Cashflow 28 April 2008 RP Revision 1 Page S18 Page 95 of 215

96 Figure ES-15 Scenario A GWh/yr, 1100 MW CCGT 20 Year Cashflow ( ) 28 April 2008 RP Revision 1 Page S19 Page 96 of 215

97 Figure ES-15a Scenario A GWh/yr, 1100 MW CCGT 20 Year Cashflow ( ) The heavy frame CCGTs are much more environmentally attractive than the existing CSC units. They also require only about 40% of the cooling water and fresh water per MWh of production. The efficiency and environmental benefits identified in Scenario A2 are even greater in this situation because all of the generation comes from the higher efficiency, lower emissions CCGTs. 28 April 2008 RP Revision 1 Page S20 Page 97 of 215

98 The CCGTs efficiency is significantly better than the existing units at all loads as was seen for Scenario A2 in Figure ES-10. This benefits all emissions, but particularly for CO 2. Figures ES-16 and Figure ES-17 show the environmental emissions rates (per month and annual) for Scenario 3 with the existing units only and Scenario A3 with the 2 CCGT units only. Figure ES-16 Scenario GWh/yr, Current Configuration Air Emissions 28 April 2008 RP Revision 1 Page S21 Page 98 of 215

99 Figure ES-17 Scenario A GWh/yr, 1100 MW CCGT Air Emissions CCGT Units 28 April 2008 RP Revision 1 Page S22 Page 99 of 215

100 As discussed above with respect to Scenario A2, the CCGT also has a more rapid response (faster start and stop); and there is a period during CCGT start-up where low NO x burner systems are in transition and NO x emissions are higher. Aeroderivative CCGTs would not normally be considered in this base load application. As noted previously aeroderivative SCGTs run at low and higher annual capacity factors will be examined in a supplemental report. Assessment results: The major conclusions of this assessment are: 1. SCGT and CCGT implementation cannot likely be implemented and placed in-service until between late 2014 and late 2015 at the earliest. 2. Existing Units 1 to 6 will need significant investment (spares purchases and detailed inspection and purchases as required) to ensure their high availability/reliability capability to the SCGT/CCGT in-service dates, and for Scenarios A1 and A2 for Units 4 to 6 to The SCGT in Scenario A1, particularly the heavy frame SCGT, will have lower efficiencies and higher CO 2 and air emissions than the existing CSC units. High part load emission rates and poorer part load efficiencies will tend to require SCGTs to run ahead of CSCs. 4. Two to four Aeroderivative SCGT units, like the LMS100, with their higher efficiencies and lower potential emissions, may operationally be a better choice for Scenario A1, if the higher capital cost can be justified, particularly where there is periodic potential for higher annual capacity factors. In detailed concept studies, consideration might also be given to parallel repowering using steam produced from an LMS100 with an HRSG in an existing steam turbine. 5. CCGT capital costs are likely between $950 and $1100/kW (2007$), excluding interest during construction. At Burrard TGS, the construction/installation costs of the second unit will cost more than the first due to the complexity of the demolition and construction effort. This will be offset by multiple unit equipment discounts and shared or common costs such as approvals and engineering. 6. CCGT installation will significantly reduce emissions of CO 2 and NO x, as well as other emissions, versus existing CSC units. CCGT will also significantly reduce the cooling water and fresh water requirements versus the existing CSC units. 7. A second large CCGT unit on the Burrard TGS site may for technical or economic reasons necessitate the prior demolition of at least Units 1 to 3 to enable construction. Alternatively the installation of the first CCGT unit could be entirely to the east of the existing Burrard TGS units or the second unit deferred if not necessary. The issue relates to Burrard TGS capacity and energy generation requirements during the demolition and construction period as well as second CCGT unit constructability. The actual timing of the first and second unit could significantly affect the actual configuration and approach. 8. Transmission interconnection through the existing switchyard may be accomplished readily and at a lower cost than for a greenfield site, but a study would be required to confirm switchyard conditions and requirements (not a part of scope of this work). 9. CCGT installations contemplated are consistent with permit requirements like the Prevention of Significant Deterioration (PSD) Permit issued in 2002 by the U.S. EPA for the proposed Sumas 2 Energy, Inc. (SE2) 660 MW CCGT which would have been sited in Sumas, Washington State in the same airshed as Burrard TGS. Of particular importance are the SE2 NOx and other emission limits for transitional periods such as startup and shut-down. While achievable, they 28 April 2008 RP Revision 1 Page S23 Page 100 of 215

101 impose additional regulatory risks on the plant and must be carefully scrutinized. In particular the interactions between those requirements and other restrictions, such as gas dispatch and contracts, would be needed. 10. SCGT installations using heavy frame gas turbines may be difficult to permit if SCR is required to control NO x. The experience with the technology is very limited and in a peaking mode has typically been hard to justify. Use of SCR with lower exhaust temperature aeroderivative gas turbine SCGTs such as GE s 40 MWe LM6000 is more common and is BACT in some jurisdictions such as California and Massachusetts. It is anticipated that it would be adaptable to the 100 MW aeroderivative LMS 100, but no LMS100 SCR unit has been installed as yet. 11. Current Effluent Permit limits for Burrard TGS should not be an issue with either CCGT or SCGT applications. Existing Air Emission Permit limits for Burrard TGS may be a problem in the case of SCGT. Special measures will likely be required to minimize noise to satisfy local needs, but will tend to have modest negative impacts on SCGT and CCGT performance (capacity, efficiency). 28 April 2008 RP Revision 1 Page S24 Page 101 of 215

102 Table of Contents EXECUTIVE SUMMARY... S1 Table of Contents...TC1 1. Task Definition and Approach Burrard TGS Background Facility Repowering Burrard TGS Repowering Studies Background - Fossil Generation Cycles Alternate Combined Cycle Gas Turbine (CCGT) Repowering Configurations Basis of Estimate Scenario A1 600 GWh/yr Simple Cycle Gas Turbines (SCGT) General Facility Description Operating Pattern Plant Layout Schedule Capital Cost OMA Cost Cashflow Environment Performance Fuelling Cost Scenario A GWh/yr, 540 MW Combined Cycle Gas Turbine (CCGT) General Facility Description Operating Pattern Plant Layout Schedule Capital Cost OMA Cost Cashflow Environment Performance Fuelling Cost: Scenario A GWh/yr, 1100 MW CCGT General April 2008 RP Revision 1 Page TC1 Page 102 of 215

103 7.2. Facility Description Operating Pattern Plant Layout Schedule Capital Cost OMA Cost Cashflow Environment Performance: Fuelling Cost Summary Appendix 1 GLOSSARY April 2008 RP Revision 1 Page TC2 Page 103 of 215

104 TASK 3 ALTERNATIVE CONFIGURATION 1. TASK DEFINITION AND APPROACH 1.1. Task Assignment The task is to prepare a report documenting the conceptual design, preliminary cost estimates, and efficiency and environmental performance for the Alternative Configuration generation concepts on the current Burrard TGS site for a 20 year life, from 2008 to 2028, for the following scenarios: replace Burrard TGS units with equivalent peaking capacity-only generation facility replace Burrard TGS units with CCGT generation to meet both capacity and some energy requirement with target of 3000 GWh/yr replace current Burrard TGS generation configuration with CCGT generation to meet both capacity and base load energy with target of 6100 GWh/yr The following scenarios reflect what was agreed to be studied by AMEC and BC Hydro: Scenario A1: 600 GWh/yr SCGT install SCGT units to displace approximately half of current six existing Burrard TGS generating units to provide 600 GWh/yr of winter peaking generation (Average 600 GWh/yr; Range of 200 to 1500 GWh/yr) Scenario A2: 3000 GWh/yr CCGT install a 540 MW CCGT unit to displace approximately half of current six existing Burrard TGS generating units to provide 3000 GWh/yr of intermediate capacity providing seasonal base load and intermediate generation through most of the year, with little or no summer generation Scenario A3: 6000 GWh/yr CCGT install two 540 MW CCGT units to displace approximately all of current six existing Burrard TGS generating units to provide 6000 GWh/yr of year round base load generation This report describes the feasibility of the new facility equipment configurations with description of equipment, conceptual design, preliminary cost estimate and expected air emissions (including GHG emissions) for the scenarios above Task Approach To complete the Tasks, AMEC and BC Hydro agreed on the following approach by AMEC: undertake initial plant walk downs with key Burrard TGS Operations/Maintenance experts and more detailed plant walk down(s)/visual inspections. review existing relevant BC Hydro documents - performance/budgeting/technical documents (reports, memos, layouts, etc.), repowering Burrard TGS and other BC Hydro combined cycle information. conduct initial and detailed follow-up interviews with key BC Hydro staff regarding past, current and future operations, maintenance, capital expenditures and organization. 28 April 2008 RP Revision 1 Page 1 Page 104 of 215

105 identify critical inspection needs not practical in the outage periods available (Study Task 1, 2 - agreed with BC Hydro). discuss Burrard TGS site reconfiguration/repowering options, constraints, performance goals and requirements with key BC Hydro staff at Burrard TGS and other BC Hydro personnel. conduct off-site reviews and analyses of collected information and develop study results, recommendations and documentation using AMEC expertise and previous experience. 28 April 2008 RP Revision 1 Page 2 Page 105 of 215

106 2. BURRARD TGS BACKGROUND 2.1. Existing Burrard TGS Facility Summary Burrard TGS is located as per Figure 2-1 on the north shore of Burrard Inlet., immediately west of the loco Refinery in Port Moody, British Columbia, and 20 kilometers east of Vancouver. Figure 2-1 Burrard TGS Location and Access 28 April 2008 RP Revision 1 Page 3 Page 106 of 215

107 Burrard TGS s six 150 MW units (Figure 2-2) are a key source of capacity and Voltage-Ampere- Reactive (VAR) support close to Lower Mainland load, allowing for transmission of large amounts of power from the northern part of the province to load in the southern part of the province. Figure 2-2 Burrard TGS Layout 28 April 2008 RP Revision 1 Page 4 Page 107 of 215

108 Burrard TGS, situated on the shoreline of Burrard Inlet at the base of a steep hillside, is a conventional, natural gas-fired, steam electric generating station consisting of six independent units, each with a boiler, turbo-generator and steam condenser. The generating units were added in stages: the first unit went on-line in 1962 and the sixth was commissioned in The Station was designed for base load operation with an annual load factor of better than 60%. Units 1 through 4 have been modified to operate either as generators or as synchronous condensers. Burrard TGS s recent primary role is to provide voltage support, peak energy and standby capacity. Burrard TGS provides 1 to 2 units for VAR support to the system almost continuously. Cooling water for the turbine-generator's condensers and for auxiliary plant use is taken from Burrard Inlet. Freshwater for boiler make-up, fire protection, domestic (potable) use and other plant cooling service is supplied from a pump house on Lake Buntzen, approximately 6 km north of the Station. The Station's unit and equipment numbering convention is from east to west, or north to south as applicable and extensive labeling is provided throughout all buildings and facilities for identification purposes. Descriptions of the existing station equipment and systems can be found in AMEC s Burrard TGS Task 1 and 2 report. General Station Data Site area 195 acres Rock excavated 750,000 cu. yds Turbine Hall height above ground 52'- 6" Bridge Crane span 110'- 0" Boiler structure height 120'- 0" Stack height above ground level 160'- 0" 2.2. Fuel Supply Natural gas supply is managed by Powerex Corp. (Powerex) and is supplied from Terasen s Coquitlam City Gate Station via a 20 diameter main at pressures between 150 pounds-force per square inch gauge (psig) and 585 psig, depending on the gas distribution system load, to a gas regulating and metering station located at the east end of the site. At the gas regulating and metering station the gas is cleaned, scrubbed and heated to 40 F to prevent any moisture in the gas from freezing in cold weather. For the existing station, the gas pressure is reduced to 75 psig, metered and supplied to two common distribution headers from which the Boilers take their individual supplies. One header supplies the main burners, the other supplies pilot gas and other various site heating services. For the SCGT, additional compression may be needed to ensure adequate pressure. The existing gas supply lines, as well as steam supply and ammonia lines, will have to be moved to accommodate SCGT and CCGT retrofits. 28 April 2008 RP Revision 1 Page 5 Page 108 of 215

109 Burrard TGS s fuel supply is purchased by Powerex in the market when Burrard TGS is expected to run. Transportation is provided by Terasen under a Bypass Agreement, which is a take or pay contract for firm gas transportation. It is a 30 year agreement ending November 1, 2029 and may be terminated by BC Hydro upon payment of a fee starting in BC Hydro may request termination by providing 12 months notice and providing a termination fee equivalent to the residual book value of the facilities (including Fraser Valley compressor) that Terasen put in place to service the contract (possibly on order of $20 million at the earliest termination date of November 1, 2009). The fuel supply contract has several issues that could potentially impact extended Burrard TGS operation. These need to be addressed and some contract terms changed in future: Single day ahead nomination for gas usage, including Friday for Saturday, Sunday, Monday Unloading and loading rates equivalent to one unit per day Current interruptible supply contracting and gas availability in peak winter periods 2.3. Permits Burrard TGS existing Effluent Permit No. PE restriction of 1.7 million cubic meters per day and an upper bound of 27 degrees Celsius would likely be applicable to any Alternative Configuration. With current units, this can significantly limit current plant output in summer, but is not expected to be an issue with any reconfiguration provided the permit conditions don t change. With respect to a new Air Emission Permit for any reconfiguration of Burrard TGS as a SCGT or CCGT facility, it is expected that the GVRD, the permitting agency, would impose strict standards similar to those set out in PSD (Prevention of Significant deterioration) Permits in jurisdictions in the United States such as California, Washington, or Massachusetts. For CCGT, the PSD Permit for the proposed SE2 660 MW CCGT that would have been sited in Sumas, Washington State in the same airshed as Burrard TGS are particularly relevant The major air issues requirements in the permit are: BACT for NO x, carbon monoxide (CO), ammonia (NH 3 ), sulphur dioxide (SO 2 ) For CCGT NO x SCR and CO Catalytic Reduction to 2 to 5 ppm (by volume, dry, 20 o C, 15%O 2 ), with a 5 ppm vd ammonia slip limit for ammonia control For SCGT, most jurisdictions require only dry low NO x combustors at about 9 ppm vd at 15% O 2 Conditions and Time Limits on Start-Up and Stop Times and transitional performance Natural gas, with a maximum sulfur content that shall not exceed 2 grains per 100 cubic feet on a seven consecutive day average basis, and 1.1 grains per 100 cubic feet on a consecutive 12 month average basis, as fuel. Annual Limits on significant emissions (for a 660 MW CCGT) of: up to tons per year of NOx up to 88 tons per year of CO up to 153 tons per year of volatile organic compounds (VOCs). 28 April 2008 RP Revision 1 Page 6 Page 109 of 215

110 up to 209 tons per year of particulate matter smaller than 10 microns (PM10, combined filterable and condensable). up to 69 tons per year of sulfur oxides (SO 2 and SO3 or H2SO4 measured as SO2). up to 14.3 tons per year of sulfuric acid mist (H2SO4). Up to 139 tons per year of ammonia. Emissions Rate Limits Daily, Less than Daily, Annual NO x HRSG stack exhaust < 2.0 ppm vd (dry, volumetric) over a three hour average at 15% oxygen. HRSG stack exhaust <daily 179 kilograms (395 pounds). HRSG stack exhaust <annual 72 tons. SO2 HRSG stack exhaust < 1.0 ppm vd over a one hour average at 15% O 2. HRSG stack exhaust < daily 86 kilograms (189 pounds). VOCs daily VOC emissions of 190 kilograms (420 pounds). Particulate Matter < 10 microns (PM10) daily filterable emissions < 88 kilograms (194 pounds). daily total PM10 emissions of 260 kilograms (573 pounds). Continuous Emissions Monitors (CEMs) on key effluents For SCGT, the air emissions permit picture is somewhat more complex. In most jurisdictions, largely non-psd regions, SCGT BACT would be compatible with the performance of dry low NOx combustors or equivalent achieving 9 ppm NOx, even 25 ppm NOx in some. In PSD regions of California and Massachusetts, the move has been to require NOx levels of 2.5 to 3.5, but these are all based on experience with recent installations of smaller 40 MWe aeroderivative gas turbines. These are equipped with high temperature SCR or smaller air diluted or water/steam cooled (for cogeneration units) conventional SCR. Alternatively significant restrictions are placed on the number of hours of operation, typically also subject to air quality conditions at the time. The use of SCR with aeroderivative gas turbines is possible because of the lower 800 to 850 o F exhaust flue gas temperatures versus the 1000 o F to 1100 o F more typical of heavy frame gas turbines. High temperature SCR catalyst can be purchased for these o F conditions. SCR for higher exhaust temperature heavy frame gas turbines would require more substantial cooling incurring significant expense and lost capacity and efficiency, but can be done but haven t been undertaken in North America as yet.. For this study Scenario A1 examines using heavy frame F Class gas turbines for peaking. A 9 ppm dry low NOx burner with no SCR was assumed since their hours of operation are about 900 and their annual capacity factor of less than 10% (and mostly outside of summer months). It is clear that in the Greater Vancouver area, this environmental performance may not be acceptable, especially if the use of the SCGT units may actually be more extensive in some years. Given this, some additional capital and performance information on 100 MWe LMS100 aeroderivative gas 28 April 2008 RP Revision 1 Page 7 Page 110 of 215

111 turbines with SCR was provided to allow BC Hydro to model the impacts of that technology. A supplemental report to this one addressing LMS100 use for peaking to intermediate use is planned Plant Operating History The Burrard TGS units, between 33 and 40+ years old, have seen a broad range of operating patterns and usage, ranging from near base load to contingency capacity to synchronous generation only. The patterns can be seen in section 2.4 of the Task 1 and 2 Report Existing Facility Condition The condition of the existing Burrard TGS units is described in detail in the Task 1and 2 Report. 28 April 2008 RP Revision 1 Page 8 Page 111 of 215

112 3. FACILITY REPOWERING 3.1. Burrard TGS Repowering Studies Several studies of Burrard TGS Repowering have been done, including: Burrard Utilization Study Combined Cycle Technical Overview. D.R. Wright, Wright Energy Services Ltd, December 1992 Combined Cycle Repowering at. Peter Calder, Derek McCann, BC Hydro/H.A. Simons Ltd, December 1995 Burrard Thermal Upgrade Project Combined Cycle Options. Sandwell Report C411/1, June 1994 The simple answer to repowering Burrard TGS would be to simply demolish the existing station almost entirely and then replace it in the same location with one of various SCGT or CCGT options. Given the needs for reliable generation in the interim from Burrard TGS, these simplistic approaches were not considered to be the practical approach that BC Hydro was looking for: demolishing all units would eliminate capacity and synchronous condenser operation that is currently being relied on to reliably serve customer electricity requirements; demolishing the entire facility and then rebuilding in place would take considerably longer than new build on site or elsewhere; building all new elsewhere on site would require significant space for new facilities and tie-in structures that is not readily available (given apparent property constraints); re-use of some units on site (U4-6) is likely a more practical use of an existing asset especially for an asset whose role changes fairly frequently Background - Fossil Generation Cycles To better appreciate the context of the Alternative Configurations, a brief description of the concepts is presented in the following sections Current Configuration Conventional Steam Cycle (CSC) The current generation cycle used at Burrard TGS is a CSC, pictured schematically in Figure 3-1. In simple terms, fuel is burned with air in a boiler producing large amounts of heat ( thermal ) energy. The boiler is lined with water filled tubes, which absorb some of the heat energy and convert the water into steam. Then the steam is further superheated in other boiler tubes. This steam is then fed to a steam turbine which converts the steam s thermal energy into mechanical energy. As the steam turbine rotates, it turns a large electricity generator which then converts the mechanical energy into electrical energy. The fuel combustion exhaust gases ( flue gas ) are cooled as low as practical to maximize fuel energy use. In Burrard TGS s case, there is an SCR device after the boiler which operates at about 600 to 800 o F to minimize emissions of NO x. The flue gas is then released back into the atmosphere through tall stacks to disperse the emissions. 28 April 2008 RP Revision 1 Page 9 Page 112 of 215

113 After extracting the available thermal energy, the steam turbine s exhaust steam goes into a condenser. The condenser is a large heat exchanger, which uses cooling water from a large source of water in large numbers of tubes, to turn the steam from the steam turbine exhaust back at very high vacuums into water, which then goes back to the boiler to start the process all over again. Large quantities of cooling water are used to minimize the temperature rise of the cooling water and thereby limit any environmental impact to the cooling water source. Figure 3-1 Conventional Steam Cycle (CSC) The CSC is typical of most large fossil fuelled power plants build up to the 1990 s and still today for coal fuelled fossil power plants. Its major issue is its limited overall generation efficiency between 32% and 37% in most existing plants. Current designs, all typically coal fuelled, can have efficiency values up to 43% due to higher pressure, higher temperature supercritical conditions. Most of the unutilized energy is lost as either exhaust flue gas at 150 to 250 o F or in the condenser cooling water. The CSC has been widely used because it has been very reliable, very capital cost effective, fuel friendly, and generally very compatible with large size generation and back end controls. For gas and oil fuels, it is much less common today because of its slower start-up times and/or lower efficiencies than gas turbine systems. 28 April 2008 RP Revision 1 Page 10 Page 113 of 215

114 Simple Cycle Gas Turbine (SCGT) Configuration The SCGT generator, sometimes known as a Combustion Turbine (CT) or Combustion Turbine Generator (CTG) is significantly different from the Conventional Steam Cycle, using what is known in Thermodynamics as the Brayton Cycle. The SCGT configuration is illustrated in Figure 3-2. It is practically speaking similar to an aircraft jet engine, except that it rotates and drives an electric generator instead of pushing an aircraft. The cycle, and indeed the machine itself, consists of four main parts: The SCGT air compressor The SCGT combustor The SCGT gas turbine The SCGT electrical generator In addition, there are the Balance of Plant systems which includes systems such as the Air Intake, Exhaust Stack, and may include back-end environmental controls such as an SCR. Figure 3-2 Simple Cycle Gas Turbine (SCGT) 28 April 2008 RP Revision 1 Page 11 Page 114 of 215

115 The air compressor sucks air through a filter and compresses it to between 10 to 40 times atmospheric pressure and feeds this compressed air to the combustor section. The compressor is highly efficient and is driven using a significant portion of the turbine s gross power. It is very important that the contaminants entering the compressor are minimized to ensure continued high efficiency and longer reliable life. The combustor combines the air from the compressor with fuel (natural gas and/or oil or other acceptable fuels) and burns them at very high temperatures. In the case of Burrard TGS, the fuel is natural gas which must be at high pressures on the order of at least 450 psi, requiring an on-site natural gas compressor. Gas turbine combustors are often very complex, resulting from designs to minimize NO x emissions, or to add moisture to minimize NO x and/or increase peak generation capacity. Some machines may have two or three systems to handle different conditions. Balancing highly efficient combustion with low emissions of NO x and CO and other unburnt carbons is a prime consideration. Unlike the boiler in the CSC case, a SCGT uses much more air per MWh typically SCGT flue gas contains 13-15% unburnt oxygen versus only 3-5% for a CSC. The SCGT gas turbine contains multiple rows of high temperature, high velocity turbine blades similar to how a steam turbine in a CSC extracts energy from steam). The gas turbine extracts energy from the hot combustion gases directly. Its spinning mechanical energy in turn drives an electrical generator, as well as the air compressor section. The flue gas leaving the gas turbine of a SCGT is very hot typically between 800 and 1100 o F. There is generally no further cooling and this hot gas is the major energy loss in the system. The high flue gas exhaust temperatures, particularly if much greater than 800 o F, make the use of an SCR generally impractical without some form of flue gas cooling which can impact capital costs and efficiency. There are two primary classes of SCGTs the Heavy Frame SCGT and the Aeroderivative SCGT. The heavy frame SCGT is widely used in the electric utility industry, especially since the early 2000 s. It is typically larger in physical size and in MW capacity. It is well suited to high efficiency combined cycle applications and for long reliable life operation. It also has significant initial capital cost advantages for simple cycle peaking. The aeroderivative SCGT uses aircraft engine technology (multiple shafts, higher speed, more exotic materials) to achieve higher simple cycle efficiency, simpler and quicker installation, and more rapid start times. They also have lower flue gas temperatures (800 o F vs o F) which is more amenable to SCR NO x control, using either high temperature SCR catalyst or more expensive exhaust dilution systems with a lower temperature SCR catalyst. The disadvantages include higher initial capital and lower capacity, shorter maintenance cycles and higher combustion NO x emissions. The heavy frame SCGT efficiency is similar to or less than many CSCs, typically between 32% and 35%, while some Aeroderivative SCGTs reach 37-40%. 28 April 2008 RP Revision 1 Page 12 Page 115 of 215

116 CCGT Configuration The CCGT generator is basically a combination of elements of the SCGT and the Conventional Steam Cycle (CSC), as illustrated in Figure 3-3, to optimize cycle efficiency. Figure 3-3 Combined Cycle Gas Turbine (CCGT) The hot flue gases from the turbine exhaust of the SCGT at o F are passed through a form of boiler known as a HRSG. The HRSG has water and steam filled tubes to capture the exhaust gas energy producing steam and reducing the flue gas temperature typically to about 180 o F. In some cases, additional fuel is burnt in the duct ( a duct burner ) between the gas turbine exhaust and the HRSG inlet or inside the HRSG itself to allow an HRSG to generate even larger amounts of steam. The steam from the HRSG is then fed to a steam turbine generator similar to that in the CSC. In the steam turbine, the energy is converted to electricity in the same manner. In the case of the CCGT, the steam turbine typically produces only between 25% to 35% of the overall electricity and hence also needs less cooling water in the condensers than a CSC of the same size as the CCGT. 28 April 2008 RP Revision 1 Page 13 Page 116 of 215

117 The HRSG often has built into it an SCR section for reducing NO x emissions to as low as 2 to 3 ppm, and in some cases also a CO catalyst to reduce CO emissions to similar levels. This can be done since the SCR catalyst typically operates between the 600 and 800 o F levels found inside the HRSG. Most large combined cycle units use heavy frame gas turbines, which typically produce about 33% of their energy from the steam turbine and have high efficiencies in the order of 45 to 55%. aeroderivative combined cycles typically produce only about 25% from a steam turbine, have lower overall combined cycle efficiencies, and suffer from poor steam cycle economies of scale Alternate Combined Cycle Gas Turbine (CCGT) Repowering Configurations The three Burrard TGS Station Repowering scenarios re-use the existing site and some existing infrastructure in building a new SCGT or CCGT plant but does not re-use the existing steam cycle equipment and is the focus of this Alternative Configuration report. There are, however, several other types of repowering: Site Repowering using only an existing site, but none (or small amount) of existing equipment or infrastructure Feedwater Heater Repowering uses gas turbine hot flue gases to preheat water going into the boiler of a CSC. This replaces the CSCs more typical steam turbine extraction preheating of feedwater. It is the simplest, least intrusive repowering system, but limited in application size. The amount of reduced extraction is generally limited by steam flow capabilities of existing steam turbine design. Provides up to a 10% efficiency increase (1 to 3 percentage point efficiency improvement). Hot Windbox Repowering uses gas turbine hot exhaust gases containing 12-15% oxygen as the air source for a CSCs boiler fuel combustion. Typically this scheme may eliminate the air preheater, but it often requires major boiler modifications, such as a larger economizer, and bypass of some boiler surfaces making for a somewhat complex, relatively expensive arrangement in many cases. Provides up to a 5% efficiency increase (0.5 to 1.5 percentage point efficiency improvement). Steam Turbine or Heat Recovery Repowering using new gas turbines and HRSGs with existing steam turbines, thereby saving the cost of the steam turbine and its associated auxiliary systems. Generally results in a slightly lower overall efficiency, on the order of 1-2 percentage points, versus a new optimized combined cycle. Often depends on the condition of the steam turbine and its compatibility with the steam production potential and conditions of the HRSG. This has been studied for Burrard TGS in the past and may still be a viable alternative, depending on the nature of the needs for Burrard TGS generation, if and when a decision to proceed with repowering is made. Provides up to a 15 to 20% efficiency increase (4 to 7 percentage point efficiency improvement). 28 April 2008 RP Revision 1 Page 14 Page 117 of 215

118 Parallel Repowering using both a SCGT with an HRSG and a conventional boiler in parallel to feed one or more existing steam turbines off a common header. An example would be if an LMS100 gas turbine was installed with an HRSG (and SCR to reduce NO x levels), and its steam was produced to match the existing boiler conditions to supply about 30 MW of steam. The existing conventional 150 MW boiler would be used at a somewhat reduced level of up to 120 MW to supplement the HRSG supply into one of the existing steam turbines. This report examines only the Burrard TGS Station Repowering concept as set out in Scenarios A1, A2 and A3, but some of the data from Task 1 and 2 and from this report may allow for other concepts to be crudely examined. 28 April 2008 RP Revision 1 Page 15 Page 118 of 215

119 4. BASIS OF ESTIMATE The estimates given herein are based on the following: 1. Capital and OMA estimates are Order of Magnitude quality, mid-2007 Canadian $$ costs, with no escalation or interest - a pre/early conceptual stage of any project which is consistent with BC Hydro s planning criteria of +30%/-15%. 2. Estimates may change somewhat between this report and the final submission based on new information 3. Client supplied mandate for high reliability and 20 year life 4. Client supplied equipment condition reports and studies 5. Client information on operating pattern and costs 6. SCGT and CCGT estimates are based primarily on recent total project costs for recent comparable CCGT projects in Ontario, adjusted using commercial CCGT software to reflect reasonable differences for a Burrard TGS brown-field installation. The estimates reflect: A conservative project management basis lump sum, fixed price, turnkey pricing carrying an inherent and not insubstantial EPC risk premium. Little change in pricing for major equipment in Canadian dollar terms despite recent Cdn/US exchange rates. Little change reflecting a recently increasingly tight market for new CCGT and specialized equipment and materials and a continuing increasingly tight labour market. 7. A generic F class SCGT and CCGT are used as the basis for the estimate including new steam turbines for the CCGT cases. For the purposes of this study, any positive differences were either offset by negatives or could be accommodated within scope fairly easily. Considerable flexibility exists in future, more detailed studies to consider several options: Repowering existing steam turbines lower efficiency, lower reliability, higher maintenance costs vs. lower initial capital cost Specific units or add-on systems having improved part load performance and emissions Potential technology improvements (ultra low NO x burners for aero-engines and new higher performance engines) not yet available and proven Larger higher efficiency G or H machines that are likely too large for the purposes herein Single shaft F class 1x1 CCGTs CCGT duct firing steam cycle augmentation (50 MW+) for peak power periods 8. Some moderately large existing Burrard TGS plant maintenance costs have been identified as single year values, but may in fact require prepayments/ stepped costs over a two to three year period. 9. The cost timing assumes that no decision on approach is taken before fall 2008 (FY2009) as part of BC Hydro s approvals process and hence any significant capital decisions are not taken until then impacting possible implementation time-frames. 10. For the purposes of the study based on BC Hydro direction, it is assumed that decisions on proceeding would not occur until fall 2008 and that it would take: i) a further 12 months to get government and public reviews done and further concept studies undertaken; ii) April 2008 RP Revision 1 Page 16 Page 119 of 215

120 months to get all the necessary environmental assessment and associated permit approvals; and iii) major equipment and/or EPC contract awards, demolition as necessary, and then about 24 months for SCGT retrofit and 36 months for CCGT retrofit leading to roughly Spring 2014 and Fall/Spring 2014/2015 earliest in-service dates for SCGT and CCGT installations respectively. 11. Study timeframe has been limited to 2008 to 2028 (20 years), covering essentially BC Hydro Fiscal Year FY2009 through FY2028. No attempt has been made to assess the termination value of the SCGT and CCGT options at the end of the period or any decommissioning costs. 12. Demolition costs have been based on a net value demolition costs the value of steel/salvageable equipment based on recent Ontario experience. 13. Operation and Maintenance (O&M) costs are based on load pattern and load following requirements as defined by BC Hydro and interpreted with BC Hydro review and acceptance for study purposes (not necessarily concurrence for regulatory purposes). 14. CCGT OMA costs are based on industry values from past projects and should be treated as indicative. Indicative annual costs are provided for information without risk protection (customers buys parts and services as needed) on an annualized basis over 20 years (as well as the associated actual per year) and with risk protection (a comprehensive Customer Service Agreement and relevant insurance) annualized as a fixed cost. 15. CCGT OMA costs can be very dependent on a variety of factors. For this reason there is a wide range of data in the public forum. Some of the factors that can significantly affect these costs include: Specifics of assumed and actual operating pattern over a short period, let alone 20 years (numbers of starts/stops; peaking vs. intermediate vs. seasonal base vs. base load), can significantly impact total costs; Contract specifics and market conditions at the time can impact total costs; Distribution of load between existing Burrard TGS units and SCGT/CCGT units can significantly impact total incremental costs; Risk aversion use of Customer Service Agreements for differing periods of time and for different scopes of supply (routine parts, unplanned and routine parts, labour, monitoring, gas turbine (GT) only, GT and steam turbine (ST), etc.), as well as insurance schemes, non original equipment manufacturer (non-oem) parts and labour usage. This can significantly impact the split of Variable vs. Fixed OMA charges in any given year and accounting/regulated rate practices; Sparing practices equipment, units, etc.; Start-up fuel and power supply and accounting (excluded herein); Existing and Incremental staff and labour rates and accounting. 16. Existing Burrard TGS units OMA and capital program depends on what units and how many are needed in the interim and long term for what role. It is assumed that Units 1 through 3 will continue to operate for capacity as best as possible until replaced or demolished to make room. It is assumed that where synchronous condenser capacity is required in future that it would be accommodated by modifying some of Units 5 and 6 (since Unit 4 is already capable). 17. Excludes major switchyard operations or changes. 28 April 2008 RP Revision 1 Page 17 Page 120 of 215

121 5. SCENARIO A1 600 GWH/YR SIMPLE CYCLE GAS TURBINES (SCGT) - REPLACE 3 BURRARD TGS UNITS WITH SCGT FOR PEAKING CAPACITY ONLY FACILITY 5.1. General In Scenario A1, three SCGT of the heavy frame F class are installed for a total capacity of about 500 MW. It is assumed that no future capability for combined cycle conversion is required (but likely a possible future option is desirable where it can be accommodated). The initial options examined included: replacing Units 1 to 3 with new simple cycle larger heavy frame gas turbines (GE701FA or Siemens 5001F or Alstom GT24) roughly three of the MW class machines. replacing Units 1 to 3 with new simple cycle aeroderivative gas turbines (GE LMS100 class) - roughly 5 x 100 MW In all cases Units 4 to 6 would be retained more or less as is. For planning purposes, it was felt that the recommended case could be readily adapted by the client for any scenario where complete demolition and replacement were desired. Specific to this case, the following were assumptions: retain Units 4 to 6 minimize capacity supply disruption during implementation completing demolition of Units 1 to 3 in advance of their being replaced is undesirable retention of at least existing capacity is necessary, but planning optimization may lead to less installed capacity but more generation response flexibility NO x emissions (and others) must meet BACT standards in most jurisdictions this is currently 9 ppm with dry low NO x combustors. Levels achievable with SCR on the order of 2 to 5 ppm are generally not practical or required for peaking units Existing facility permit levels for NO x, water usage, etc. must not be compromised Permits will likely necessitate some form of start-up/shut-down limits Permitted emission limits will be strict, as similar as practical to those identified with the proposed SE2 660 MW CCGT which would have been sited in Sumas, Washington State in the same airshed as Burrard TGS Gas supply will be optimized, including dispatch arrangements, to allow unhindered unit dispatch Noise will be approximately 58 dba at plant boundary Stacks, normally about 50 to 60 feet for SCGT study purposes, have been modeled here at 150 feet to avoid impingement on existing unit structures and surrounding higher landscape 28 April 2008 RP Revision 1 Page 18 Page 121 of 215

122 The SCGT option has several positive and negative features, both general and Burrard TGS specific, which must ultimately be addressed in both planning studies and in actual implementation: Short start/stop times typically 30 minutes (10 for aeroderivative LMS100) allowing for shorter uneconomic start-up times and lower efficiency stages Higher start up NO x levels, but for brief times Variable generation with ambient temperature, but opportunities using evaporative cooling and/or duct burners to make up or increase generation Limited turndown while maintaining high efficiency and low NO x levels - typically minimum load of 50 to 65% of Maximum Continuous Rating (MCR) Minimal space, except if option of CCGT upgrade must be retained Gas pressures required are higher, likely necessitating an on-site compressor Load swings and two shifting can be readily followed, but can result in gas-electricity dispatch interface issues technical and economic implications Not necessarily consistent with current roughly 150 MW/day swing permissible under gas supply agreement at Burrard TGS Full load NO x is typically slightly higher using current SCGT BACT (low NO x burners at 9 ppmv at 15% O 2 ) versus existing Burrard TGS units on gas with SCR (17-25 ppm permit at 3% O 2 = about 7 to 10 ppm at 15% O 2 equivalent). Reduced start-up/shut-down, warm-up times, and low load out-of-merit operating times may negate most of this higher load NOx emissions for cases having low annual capacity factors and more starts/stops Requires additional rock removal and disposal from north east side of current Units 1 to 3. SCGT has minimal water requirements for cooling from Burrard Inlet or fresh water from Lake Buntzen (benefit) May allow more effective use of existing Burrard TGS steam units in providing added flexibility(benefit) Requires additional rock removal and disposal from north east side of current Units 1 to 3 (benefit) May, in the envisioned dispatch, require significantly more low load, less efficient operation of Burrard TGS Units 4 to 6. This is offset by less overall run time on gas by either the SCGTs or by Burrard TGS 4 to 6. Offers real opportunities for optimizing. (benefit) 5.2. Facility Description This section will describe the basic plant option and its layout, with brief descriptions of the major parts of the plant: GT Environmental Controls Interface with existing facility Changes to existing facility 28 April 2008 RP Revision 1 Page 19 Page 122 of 215

123 The SCGT layout is based on the F class of heavy frame gas turbines, which are one of the leading gas turbines used in the electric generation utility industry. The F class SCGT nominally produces between 170 to 200 MW per machine. There is a large amount of experience with most of the major difficulties understood and addressed. They have a number of features well suited to this application: Moderate footprint Good simple cycle efficiency of about 33% to 35% (although less than a smaller aeroderivative SCGT), although efficiency is generally considered less significant for a true peaker Low dry low NO x burners available (9 ppm) and well proven as industry BACT in most jurisdictions eliminates need for added auxiliary water and/or steam systems and SCR ammonia systems and ammonia slip emissions Quick start-up and shutdown 30/10 minutes and rapid turndown response rates Simplicity of installation Competitive marketplace Available in outdoor (individual noise/weather) enclosures or indoor building applications Reasonable fit for 3 within confines of Burrard TGS facilities Figure 5-1 Heavy Frame F Class SCGT (Ref: Siemens SCGT5000F Handbook) 28 April 2008 RP Revision 1 Page 20 Page 123 of 215

124 Three F class generic machines were selected for the purposes of this study. This appeared optimal based on site space availability, minimal existing unit outage during construction and minimizing capital in an uncertain environment while providing spares for enhancing the availability of Units 4 to 6 reliability. Existing Burrard TGS Units 4 to 6 are assumed retained more or less as is. SCGTs will not enter service until 2014 at the earliest and Burrard TGS still needs to be a reliable supplier as per Task 1 and 2 Report Scenario 1. Given this, much of the work and capital investment on Units 4 to 6 would apply in the years 2009 to After the SCGTs enter service, Units 4 to 6 are assumed to see minimal operation, but given the relative performance of Units 4 to 6 versus SCGTs that may not be the case and some further optimization between the two types of generation would logically follow. Existing Units 1 to 3 will also still need to be reliable suppliers as per the Task 1 and 2 report Scenario 1 until the SCGT units come into service. The earliest possible is 2014, which has been used as the date for cash flow purposes in this report. Given this, much of the work and capital investment set out in the Task 1 and 2 report would apply in the years 2009 to Once the SCGTs are operational, Units 1 to 3 can be decommissioned (the boilers may possibly be demolished) and parts used to maintain Units 4 to 6, minimizing further capital expenditure on these Units Options - Aeroderivative LMS100 Class An alternative to the heavy frame gas turbines would be an aeroderivative gas turbine such as GE s LMS100 class machine. The LMS 100 is actually a hybrid between true aeroderivative and a heavy frame machine. They are smaller (100 MW), more efficient in simple cycle and faster starting than an F class heavy frame machine. The LMS100 is, however, a newer less proven technology employing intercooling to provide higher efficiency, but resulting in more complexity, more space required (for intercooler and heat exchange systems), higher combustion NO x emissions, and more capital expense. There is, however, a better opportunity to add SCR to keep NO x emissions lower than for the heavy frames and below current Burrard TGS levels. In addition, their higher efficiency will afford some savings in fuel and in CO 2 emissions. For the purposes of this assessment these machines were not used, but in any future more detailed studies there is no reason not to include them. This includes the dry low NOx combustion technology currently in development and expected to be broadly adopted for use in preference to current water or steam injected versions (for NOx control). Some rough performance and emissions data are provided to allow BC Hydro to do some sensitivities and a supplemental report is planned for completeness. 28 April 2008 RP Revision 1 Page 21 Page 124 of 215

125 Figure 5-2 Aeroderivative GE LMS 100 SCGT (Ref: General Electric LMS 100 Sales Literature) 5.3. Operating Pattern BC Hydro provided an operating pattern for a typical week for the current Burrard TGS configuration of 6 steam cycle units and identified that a typical year would consist of three weeks of this pattern in the winter period for about 300 GWh of production (Table 5-1). Further, a non-typical or dry year might occur every three or four years at roughly 1500 GWh/yr. An average of 600 GWh/yr (about 6.25 weeks) was used as the basis for planning. It was also assumed that 1 unit of the synchronous condenser was required 90% of time and a second unit 25% of time. This is shown in Figure 5-3. A similar basis was used for the Scenario A1 using SCGTs, except that the SCGTs were used as the primary generation source and the existing Burrard TGS Units 4 to 6 were used for peaking. This does mean that less time is required to start units up before the actual need. The pattern used is illustrated in Figure 5-4. It results in the SCGTs producing about 454 GWh/yr or about 78% of the generation and the existing Burrard TGS Units 4 to 6 producing 127 GWh/yr or about 22% of the generation (plus synchronous generation after a synchronous condenser conversion kit is added). This gives SCGTs a 9.6% annual capacity 28 April 2008 RP Revision 1 Page 22 Page 125 of 215

126 factor (ACF) and 11% operating factor (OF), and existing conventional Units 4 to 6 a 3.5% ACF and 7.6% OF (up to 27-43% OF with synchronous condenser operation required). Figure 5-3 Scenario 1 Conventional Configuration Weekly Profile Weekly Profile for 6-Unit Peaking on Mon-Fri with Startups On Sat/Sun Full Load 4-7 pm; then back off 3 units Plant Output MW Plant Output Units 1 to 3 Units 4 to SAT SUN MON TUE WED THUR FRI Time of Day Per Week of Operation The operating/dispatch pattern for any of these weeks is per Figure 5-4. As a result of this operating pattern request, two aspects were treated seriously here, but are highly subject to uncertainty: All units will be in-service for 20 years. All units must be available for generation service (reliably) during peak periods meaning there is little tolerance for failures to start, forced outages while needed, and little/no unit sparing assumed. For the purposes of this study, this model is likely adequate, however, an initial assessment strongly suggests that actual operation would tend to favour a more blended result with more partial steam turbine use at higher loads where longer sustained runs are needed and with some (not all) of the SCGTs providing more on-off peaking support during peak periods of days. This will reduce overall uneconomic run-time and thereby produce minimal overall emissions and gas consumption. This is, however, more in the realm of a system analyses than could be undertaken here. 28 April 2008 RP Revision 1 Page 23 Page 126 of 215

127 Figure 5-4 Scenario A1 SCGT Weekly Profile Scenario A1 - Weekly Profile Plant Output MW SAT SUN MON TUE WED THUR FRI Time of Day Per Week of Operation Plant Output Units 4 to SCGT Units SC1 to SC Plant Layout Figure 5-5 is an aerial photograph of the Burrard TGS site. This option addresses adding the SCGTs at the right end (nominally the east end) of the plant where there appears to be adequate space to install several units without disrupting plant operations and provides the potential for a relatively easy change-out to the existing switchyard. It does require significant rock removal in the area, but the encroachment on the SCR ammonia storage area should not be an issue. An alternative siting would be at the left or west end of the plant, but this involves issues with high water lines, land ownership, moving facilities, eliminating employee parking areas, and major changes to switchyard connections. Figure 5-6 provides a conceptual layout for placing 3 F class SCGT generators at the east end of the plant. It will require significant excavation of the area to the east of the existing Unit 1 towards the ammonia storage area, as well as an extension of the transformer area. It will, however, line up reasonably well with the existing switchyard and require minimal changes to ongoing operations of the existing facility. 28 April 2008 RP Revision 1 Page 24 Page 127 of 215

128 Construction logistics will be the major challenge to receive and manage the handling of the large SCGT equipment. There is, however, opportunity to use the water unloading ramp (if the equipment can be moved down the rather narrow transformer row, through a landing at the east end of the plant or through the IOCO refinery road area. Figure 5-5 Burrard TGS Site Layout Figure 5-7 is a closer look at the layout. It is possible to see the extent of the excavation from the existing rock faces at the back and end of the Unit 1 transformer area. It is possible that a larger rock cut may be needed to accommodate construction logistics, but that will require detailed study. It is evident, given its closeness to the existing structure, to the elevated switchyard and SCR ammonia storage area that the stacks of these SCGTs will have to be taller than the 16 to 20 meters typically used. It is also evident that some early changes will be needed to the existing natural gas, steam and ammonia supply lines that pass through or near the SCGT areas early in the project schedule. This could occur during a relatively short station outage for tie-ins during a summer outage period. 28 April 2008 RP Revision 1 Page 25 Page 128 of 215

129 Figure 5-6 Heavy Frame SCGT Site Layout In order to implement this solution, the following additions are required: Civil: New: Stacks; gas turbine building; main transformer enclosures; GT air intake Modified: Steam Turbine Foundation; switchyard reconfiguration (out of scope); Demolition: SCR ammonia enclosure rock; Units 1, 2 boiler and asbestos (options) Mechanical: New: Modified: Steam turbine and auxiliaries; gas turbines and auxiliaries; HRSGs and auxiliaries and piping; natural gas, steam and ammonia lines to existing units Boiler feedwater system; cooling water system 28 April 2008 RP Revision 1 Page 26 Page 129 of 215

130 Figure 5-7 Close-Up of Heavy Frame SCGT Site Layout Electrical: New: Modified: Main Output transformers; Units station service transformers; HV switchgear; motor control centers (MCC) and cabling Existing MCC and switchgear; switchyard reconfiguration Instrumentation and Control: New: New central distributed control system (DCS) GTs ST, HRSG and auxiliaries Modified: Existing steam turbine DCS For the case of using an aeroderivative LMS100, one possible configuration would see three LMS100 machines configured as in Figure 5-8 and in a close-up view in Figure April 2008 RP Revision 1 Page 27 Page 130 of 215

131 Figure 5-8 LMS 100 x 3 Site Layout In this configuration, it was assumed that you would demolish Units 1 and 2 boilers to make space for two of the LMS100 units prior to the operation of the SCGTs. Units 1 and 2 during demolition and SCGT construction would thus only be available as synchronous condensers probably for a 1 to 2 year period. An alternate possibility is to extend the three LMS100s into the ammonia storage area, but the requirement may exceed that of the heavy frame cases. Another possibility may be to install two LMS100s and parallel power steam turbine # 2. If LMS100s are considered seriously then several of these kinds of options are worth study. 28 April 2008 RP Revision 1 Page 28 Page 131 of 215

132 Figure 5-9 Close-Up of LMS 100 x 3 Site Layout 5.5. Schedule The Scenario A1 schedule (Figure 5-10) shows the first unit in-service in Q2 of 2014 with about 3 months between unit in-services and the 3rd unit coming into service in Q This is based on a two year SCGT order to In-Service timeline. The order placement date is Q April 2008 RP Revision 1 Page 29 Page 132 of 215

133 Figure 5-10 Schedule Scenario A1-3 Heavy Frame F Class SCGT 5.6. Capital Cost The Scenario A1 capital cost is presented in Table 5-1. The capital cost estimate is based on a review against Ontario lump sum, turnkey, EPC plant estimates, with adjustments for scope differences, price increases and existing facilities at Burrard TGS. There have been considerable increases in prices in major equipment, construction labour, and commodity materials recently; hence, prices tend to be higher than historic levels. The lump sum EPC pricing basis tends to result in higher direct costs and lower contingency and indirects than built up costs. The estimates are reasonable compared to other recent built up estimates for similar sized conceptual plants for BC Hydro and others, recognizing that one generally pays a modest premium for a fixed price lump sum contract. Based on this, the estimate appears reasonable and likely to be + 30%/-15%. Table 5-2 presents the timeline assumed and a reasonable associated cashflow for analyses purposes. There is considerable room for variation in the cashflow depending on market and contracting approaches. 28 April 2008 RP Revision 1 Page 30 Page 133 of 215

134 Table 5-1 Capital Cost Scenario A1-3 Heavy Frame F Class SCGT 28 April 2008 RP Revision 1 Page 31 Page 134 of 215

135 Table 5-2 Timeline and Cashflow Scenario A1-3 Heavy Frame F Class SCGT Similar capital cost and cashflow charts for the 3 Unit aeroderivative LMS100 option are provided in Table 5-3 Capital Cost and Table 5-4 Timeline and Cashflow. 28 April 2008 RP Revision 1 Page 32 Page 135 of 215

136 Table 5-3 Capital Cost Scenario A1-3 Aeroderivative LMS100 Class SCGT These LMS100 costs include allowances for the implementation of high temperature SCR and some incremental conservatism reflecting the early commercialization of the technology and a lack of competitive offerings at present. 28 April 2008 RP Revision 1 Page 33 Page 136 of 215

137 Table 5-4 Timeline and Cashflow Scenario A1-3 Aeroderivative LMS100 Class SCGT 5.7. OMA Cost The heavy frame SCGT OMA costs are illustrated in Table 5-5. It is assumed that another 5 incremental staff are required beyond those for Burrard TGS Units 4 to 6. In some classic standalone SCGT plants, 5 to 10 staff are used, with management as a satellite facility provided by another location. No initial unit start-up power was charged to the facility although that is often done. Table 5-5 SCGT OMA also provides two types of OMA for information purposes. The base case is the No Risk Mitigation case: the owner has no Customer Service Agreement (CSA) or Long Term Service Agreement (LTSA) with an OEM for specific 20 year parts and service. The second is a Risk Mitigation case: a CSA or LTSA is established for a given period and operating pattern, and specified O&M services are paid for at a fixed rate over the period. The base case is likely too expensive for a peaking SCGT due to its limited and uncertain need resulting from its limited operating hours and uncertain numbers of starts and stops. The flexibility to seek after-market parts may be more economic. Care must be taken in applying 28 April 2008 RP Revision 1 Page 34 Page 137 of 215

138 these costs as they (in absolute $ terms or in Fixed and Variable Cost terms) can vary significantly for peaking cases depending on specific circumstances and arrangements. Table 5-5 OMA Costs Scenario A1-3 Heavy Frame F Class SCGT Aeroderivative LMS100: Indicative major maintenance costs are illustrated in Table 5-6, but must be recognized as being very preliminary as there is limited experience on this equipment to date and limited experience with vendor service agreements. A Customer Service Agreement (CSA) or Long Term Service Agreement (LTSA) with an OEM is assumed to be in effect. Expected Maintenance of the LMS100 gas turbine engine follows a 50,000-hour cycle (about six years for base load operations with 8,760 operating hours per year). Preventative maintenance for the engine primarily consists of regularly scheduled borescope and package inspections. After 25,000 hours of operation (three years at base load), the hot section and combustor will need to be refurbished. After 50,000 hours (six years at base load), the entire engine will need to be overhauled. Frequent starts and stops do not affect repair or overhaul intervals. 28 April 2008 RP Revision 1 Page 35 Page 138 of 215

139 Preventative maintenance work can be performed by trained plant operators either independently or in conjunction with GE Aero Energy technicians under a maintenance contract. Major maintenance will be performed by personnel from an authorized depot. Scheduled maintenance events from inspections to overhauls can be completed with minimum downtime, usually on weekends or other low demand periods (usually 1-5 days; assuming a Lease or exchange engine is used during overhaul). The estimates assume that the plant joins General Electric s lease engine program for use during major maintenance events. For scheduled maintenance, a lease engine can be on-site prior to shutdown and the lease engine change out can be accomplished in 24 to 48 hours. For unscheduled engine change outs, a lease engine can be delivered within 72 hours. Price of the optional lease engine program is divided into an annual fee and weekly usage charges. Based on some initial GE information, the conceptual costs for the program from GE (in Year 2007 Cdn$) for the 3 LMS100 machines are: Table 5-6 Maintenance Costs Scenario A1-3 Aeroderivative LMS100 Class SCGT Element Price ( 000$/yr) Peaking Intermed Base Preventative Maintenance $100 $150 $200 Hot Section Refurbishment (at 25,000 Hrs) $750 $1,500 $2,700 Engine Overhaul (at 50,000 Hrs) $1,200 $2,300 $4,200 Optional Lease Engine Annual Fee $1,500 $1,500 $1,500 Total $3,550 $5,450 $8,600 In addition to these costs would be the others similar to those for the heavy frame in Table 5-5. These will be addressed in a supplemental LMS 100 report. For a heavy frame peaking SCGT, one might consider after-market parts and third party maintenance contractors. This would be highly unlikely at the stage of the LMS 100 s development. Similarly, one might choose to opt out of the lease engine program for a peaking facility, but for any subsequent lease engine needed the costs would increase significantly and the timeframes to deliver and swap a lease engine would increase significantly. For this analysis, the status of the technology a conservative approach was adopted Cashflow Table 5-7 presents the Cashflow for Scenario A1. It provides a capital and OMA cashflow (2007 Cdn$) from FY2008 through FY2028. It assumes that Units 1 through 6 (typically 25% generation from U1-3 and 75% from U4-6) operate until the SCGT units come on line in FY2014 at which time the pattern in Section 5.3 is used. The existing unit cashflow used is basically the current investment program adjusted to reflect the low Units 4 to 6 ACF/OF after the SCGTs come on stream. This lower Unit 4 to 6 OMA/capital stream is also consistent with the fact that spare equipment from Units 1 to 3 can be retained to support Units 4 to April 2008 RP Revision 1 Page 36 Page 139 of 215

140 Table 5-7 Cashflow Costs Scenario A1-3 Heavy Frame F Class SCGT Years 2008 to April 2008 RP Revision 1 Page 37 Page 140 of 215

141 Table 5-8 Cashflow Costs Scenario A1-3 Heavy Frame F Class SCGT Years Similar information for the aeroderivative option will be examined in a supplemental document to this report Environment This section will address the environmental emissions associated with the facility and it s compatibility with existing and likely future new generation permits. 28 April 2008 RP Revision 1 Page 38 Page 141 of 215

142 Air Environment Single Unit Management: Typical air emission rates of one SCGT unit on a stand alone basis (or 3 units in parallel) at various loads at International Organization for Standardization (ISO) standard conditions (59 o F, psia, 60% relative humidity (RH)) are presented in Table 5-9. Table 5-9 Scenario A1 - Single SCGT Unit Emissions with Load (Heavy Frame F Class SCGT) Unburnt hydrocarbons (UHC) are used in the analyses as Particulate matter (PM) which is not absolutely correct. These rates are based on emission values for NO x, CO and unburnt hydrocarbons (UHC) in Table 5-10 and Table Large machines typically have a significant transition in NOx and CO and UHC at around the 50% MCR load point. These Dry Low NO x (DLN) Burner systems switch over to a second diffusion burner system to maintain a stable flame which is higher in NO x. The specifics depend on the vendor and on continuing improvements. The values used are shown table April 2008 RP Revision 1 Page 39 Page 142 of 215

143 Table 5-10 Scenario A1 Low Load SCGT NOx and CO Emissions (Heavy Frame F Class SCGT) 28 April 2008 RP Revision 1 Page 40 Page 143 of 215

144 Table 5-11 Scenario A1 Low Load SCGT UHC Emissions (Heavy Frame F Class SCGT) 28 April 2008 RP Revision 1 Page 41 Page 144 of 215

145 Table 5-12 Scenario A1 Low Load SCGT Emission Values Used (Heavy Frame F Class SCGT) Note that there is no SCR assumed for heavy frame SCGT NO x reduction. The way in which one manages the output of the three SCGTs can have an effect on overall emissions. The single unit emissions curves (or three units acting in parallel) are presented in Figure 5-11 (NO x, UHC, SO 2, NH 3, CO) and Figure 5-12 (CO and CO 2 ). Figure 5-11 Scenario A1 Single SCGT or Parallel Unit Emissions vs. Load (Heavy Frame F Class) Emissions vs Load Emission Rate NOx, UHC, SO2, NH3 g/kwh Net CCGT Load MW CO Emission Rate g/kwh NOx UHC SO2 NH3 CO 28 April 2008 RP Revision 1 Page 42 Page 145 of 215

146 Figure 5-12 Scenario A1 Single SCGT or Parallel CO and CO 2 Emissions vs. Load (Heavy Frame F Class) Emissions vs Load Emission Rate CO g/kwh Net CCGT Load MW CO2 Emission Rate g/kwh CO CO2 Multi-Unit Load Management: For three units, one would typically turn on or off individual units to manage a response to load. Table 5-13 presents the emissions results at ISO conditions based on a variety of operating patterns. Typically at the 40% load point where NO x and CO emissions are high, all three units are at the same load not something you would tend to do. It shows that you could theoretically one could get down to as low as 30% load on the 3 units before encountering higher emission levels. Table 5-13 Scenario A1 Multi-Unit Load Management - Emissions vs. Load (Heavy Frame F Class) 28 April 2008 RP Revision 1 Page 43 Page 146 of 215

147 These emissions rates are based on the volumetric emission rates presented in Table Table 5-14 Scenario A1 Multi-Unit Load Management PPM Emissions vs. Load Figure 5-13 (NO x, UHC, SO 2, NH 3, CO) and Figure 5-14 (CO, CO 2 ) shows the trend of the emission factors possible if one is able to manage the turndown and shutdown of units effectively. Figure 5-13 Scenario A1 Multi-Unit Load Management - Emissions vs. Load (Heavy Frame F Class) Emissions vs Load Emission Rate NOx, UHC, SO2, NH3 g/kwh Net CCGT Load MW NOx UHC SO2 NH3 CO Emission Rate CO g/kwh 28 April 2008 RP Revision 1 Page 44 Page 147 of 215

148 Figure 5-14 Scenario A1 Multi-Unit Load Management CO and CO2 Emissions vs. Load (Heavy Frame F Class) Emissions vs Load Emission Rate CO g/kwh CO2 Emission Rate g/kwh Net CCGT Load MW CO CO2 Aeroderivative gas turbine with SCR and CO catalyst would have substantially lower emission rates for NOx and SOx and slightly lower for CO2 due to a higher efficiency. These are derived from volumetric emissions levels shown below of approximately. Note that the 5 ppm (volume, dry basis) here is at a reference oxygen in the flue gas of 15%, versus a reference oxygen of 3% for a CSC. For a SCGT or CCGT configuration, the 5 ppm at 15% oxygen would be comparable to a 15 ppm to 10 ppm respectively at a 3% oxygen reference for a CSC plant. 28 April 2008 RP Revision 1 Page 45 Page 148 of 215

149 Figure 5-15 Scenario A1 Aeroderivative with SCR versus Load The existing CSC units will continue to operate at current emission levels as per Figure 5-16 (NO x, UHC, SO 2, NH 3, CO) and Figure 5-17 (CO 2 ). 28 April 2008 RP Revision 1 Page 46 Page 149 of 215

150 Figure 5-16 Scenario 1 Existing Units (NO x, UHC, SO 2, NH 3, CO) Emissions vs. Load 28 April 2008 RP Revision 1 Page 47 Page 150 of 215

151 Figure 5-17 Scenario 1 Existing Units CO 2 Emissions vs. Load CO2 Emission Rate vs Net Output CO2 Emissions kg/kwhn MW net CO2 kg/kwhn Heat Rate Impacts with Load: Figure 5-18 illustrates the impact of load on both the existing configuration CSC units and the heavy frame SCGTs. It is apparent that the SCGT has a poorer heat rate at all load levels than the existing units, particularly at lower loads. This would suggest that the CSC units would run first, versus the model used in the analyses where the SCGTs run ahead of the CSCs. This is one strategy, and may be the best one since the SCGT could start up often and quickly. Alternatively, if some SCGTs and CSC units are run together often, one may want to run the SCGTs at full load and the CSCs at low loads to get the best overall efficiency and emissions performance. In reality, one would see a mixture of all units in different ways. Life of the existing CSCs is one issue as well. 28 April 2008 RP Revision 1 Page 48 Page 151 of 215

152 Figure 5-18 Scenario A1 SCGT and Existing Units Heat Rate vs. Load The situation with an aeroderivative engine may be different given its higher MCR efficiency, but it also will have poorer part load performance. Curves for it will be added later. The emission rates and annual amounts for Scenario 1 are repeated here for reference purposes in Figure 5-19, as is CEM data (Figure 5-20). This is compared with those for Scenario A1 (600 GWh, 450 MW SCGT) in Figure From a comparison of these two curves, one can see that for a heavy frame SCGT: NO x rates are substantially higher for Scenario A1 CO 2 rates are slightly higher for Scenario A1 NH 3 rates are substantially lower for Scenario A1 (no SCR ammonia slip) 28 April 2008 RP Revision 1 Page 49 Page 152 of 215

153 Figure 5-19 Scenario GWh/yr Current Configuration Emission Rates and Annual Emissions As noted previously, a range of values is possible depending on the condition of equipment such as the SCR and the combustion equipment and on things such as the sulphur in the natural gas. Other variations such as operating pattern and deterioration are smaller and usually 28 April 2008 RP Revision 1 Page 50 Page 153 of 215

154 within +/-5 to 10%. A range is provided in annual emissions that reflects the potential differences. They do not however affect the station s ability to meet current permit values. Some reductions are also achievable through improvements (airpreheater seals and turbine efficiency). This is generally slightly higher than is seen in station CEM data shown in Figure Figure 5-20 Scenario 1 Existing Units CEM Emission Data CEM Emissions vs Load NOx, CO, MWg NOX ppm NOX mg/m3 NOX kg/hr CO ppm O2 % Fuel scfh^6 Poly. (Fuel scfh^6) Fuel, O2 28 April 2008 RP Revision 1 Page 51 Page 154 of 215

155 Figure 5-21 Scenario A1 600 GWh Emission Rates and Annual Emissions 3 SCGT and Units 4 to Water Environment Water consumption and cooling water requirements in Scenario A1 for the SCGT units are minimal. It is substantially less than current CSC installation. There is no steam cycle requiring once through cooling and no boiler blowdown requiring demineralized water. There are very low requirements for lube oil coolers and generator coolers. If inlet evaporative coolers are used in 28 April 2008 RP Revision 1 Page 52 Page 155 of 215

156 summer to minimize ambient temperature derates, fresh water consumption may be significant, up to about 90 USGPM = 200,000 USGPD or about 0.75 MML/day if for 24 hrs, which is unlikely. For most of the year water use would be almost zero Other Environment Noise is another primary environmental impact will require significant effort in the given environment. The primary impact will be on plant performance, costing up to 1% reduction in capacity and 1% in performance (i.e. 1% higher heat rate) Performance Figure 5-22 illustrates the heat balance for Scenario A1 for a GE 7FA as an example. As a result, the outputs are slightly less than the generic values used in the study, which will vary with the engine selected. It provides the basic information needed to understand the fuel and air inflows and the electricity generation. It also provides the new and clean heat rate defined as a Low Heating Value (LHV) heat rate. This is most often how the gas turbine industry provides heat rate or efficiency. It must, however, be converted to a Higher Heating Value (HHV) basis to use it with fuel pricing, which is usually quoted on a HHV basis. For natural gas, multiply LHV heat rate by 1.11 to get the HHV heat rate. For the efficiency, divide the LHV efficiency by 1.11 to get the HHV efficiency For distillate oil (#2 oil), you use approximately 1.06 in the same manner In developing plans, one must also address the difference between new and clean and typical performance. Gas turbines tend to get fouled with contaminants from the air and as a result experience both a permanent degradation and a temporary/recoverable degradation. The temporary degradation will be recovered when the machines are washed either using on-line techniques or through periodic off-line washes. This degradation of both capacity and heat rate (i.e. increased heat rate or reduced efficiency) can be in the order of 2% or more depending on the environment. Further, there can be other factors that cause a higher than expected average MCR heat rate and lower than expected MCR capacity. Ambient temperature and relative humidity also have an effect on generation capacity and heat rate. Capacity tends to decrease with higher ambient temperature and heat rate rises slightly. Part load operation also has a significant effect on efficiency at loads below 50 to 70%. 28 April 2008 RP Revision 1 Page 53 Page 156 of 215

157 Figure 5-22 SCGT Performance Information New and Clean Note: To convert LHV to HHV, multiply by 1.11 Figure 5-22a SCGT Performance Information New and Clean The base SCGT design incorporates evaporative inlet air cooling to reduce the impact of high summer ambient temperatures on output and efficiency. Figure 5-23 illustrates the impact on the Base output and heat rate throughout the year at Burrard TGS, as a function of average monthly ambient temperature and relative humidity (Environment Canada data for Port Moody Glenayre). 28 April 2008 RP Revision 1 Page 54 Page 157 of 215

158 Figure 5-23 SCGT Performance vs. Time of Year at Burrard TGS Ambient Conditions Burrard SCGT Performance % of Base MWn and Base Heat Rate 105.0% 104.0% 103.0% 102.0% 101.0% 100.0% 99.0% 98.0% 97.0% 96.0% 95.0% Jan Feb Mar Apr May Jun Jul Net Month Capacity MWn Aug Sep Oct Nov Dec Net Heat Rate Fuelling Cost The Base new and clean SCGT capacity (MW) and efficiency (kj/kwh on an HHV basis) at ISO conditions of 20 o C and 60%RH is nominally 514 MW and 11,000 kj/kwh (10,466 BTU/kWh). This is a generic value since 3 F class machines from various vendors can produce anywhere from 500 to 560 MW. As per Figure 5-22, the ambient temperature will affect summer and winter capacities and heat rates and hence generation fuelling costs. Assuming an average 5% degradation and other losses allowance, the more typical MCR heat rate value becomes kj/kwh (11,000 BTU/kWh). Assuming a $6/MMBTU(HHV) gas cost, its fuelling cost would be $66/MWhe. 28 April 2008 RP Revision 1 Page 55 Page 158 of 215

159 6. SCENARIO A GWH/YR, 540 MW COMBINED CYCLE GAS TURBINE (CCGT) - REPLACE BURRARD TGS UNITS 1 TO 3 WITH CCGT GENERATION 6.1. General In Scenario A2, existing Burrard TGS Units 1 to 3 are replaced with a single new MW CCGT unit, including 2 heavy frame F Class gas turbines ( MW) and 2 HRSGs and 1 steam turbine ( MW). Existing Burrard TGS Units 4 to 6 would again be retained more or less as is, but function as capacity insurance and generate less energy. Unit 4 can act as a synchronous generator, and either of Units 5 or 6 could be retrofitted with synchronous generation capacity if needed for summer use. An alternate would be to retain Unit 3 generator in-place solely for synchronous generation and use Unit 4 as well since it is already so equipped. Two heavy frame F Class gas turbines/hrsgs would be located east of Units 1 to 3 powerhouse and boiler and the Unit 1 steam turbine replaced with a new steam turbine. Alternatively, Units 1 and 2 boilers and powerhouse could be demolished and then the gas turbines/hrsgs added in that space and the steam turbine in place of Unit 3, but this would not allow for generation or synchronous generation in the interim or for the subsequent retrofit of a further CCGT (i.e. Scenario A3) later. This scenario will require excavation of rock to the east of Unit 1 and also of some of the foundation of Unit 1 steam turbine. The demolition of the Units 1 boiler (possibly also boiler 2) may also (but not necessarily) be undertaken during this period. Unit 1 steam turbine would in all likelihood be removed and after reconstruction replaced with a new steam turbine in its place (alternatively repowered, but unlikely given age and efficiency). Units 3 and 4 (and/or 2) could be retained for synchronous condenser purposes in the interim, while the needs for that capability are examined in detail. This also allows for Scenario 3 to proceed as a follow-on project. Units 4 to 6 will be retained more or less as is. Some spares from Units 1 to 3 will be retained for reliability purposes. Some upgrades will proceed to assure a 20 year life. Consideration in detailed studies should also be given to using an existing steam turbine and repowering it, but the impact for the purposes of this study is likely insignificant. The concept would re-utilize a lot of the existing site infrastructure cooling water intake and delivery, administration building, cranes, ammonia storage. While retaining Units 4 to 6 more or less as is seems to make sense for planning purposes, it was felt that the recommended case and Scenario A3 provide sufficient detail to be readily adapted by the client for any other Scenario A2 where complete demolition and replacement were desired. Specific to this case, the following were assumptions: retain Units 4 to 6 28 April 2008 RP Revision 1 Page 56 Page 159 of 215

160 minimize capacity supply disruption during implementation complete demolition of Units 1 to 3 in advance of their being replaced is undesirable retention of at least existing capacity is necessary, but planning optimization may lead to less installed capacity but more generation response flexibility NO x emissions (and others) must meet BACT standards currently 3 to 5ppm with SCR similar to that employed on existing Burrard TGS steam turbine units Existing facility permit levels for NO x, water usage, etc. must not be compromised Permits will likely necessitate some form of start-up/shut-down limits Permitted emissions limits will be similar to those identified with the proposed SE2 660 MW CCGT which would have been sited in Sumas, Washington State, in the same airshed as Burrard TGS Gas supply will be optimized, including dispatch arrangements, to allow unhindered unit dispatch Noise will be approximately 58 dba at plant boundary Stacks will be nominally 150 feet for study purposes, but modeling and impingement on existing unit structures may necessitate taller stacks up to slightly higher than existing boiler structures The CCGT option has several positive and negative features, both general and Burrard TGS specific that must ultimately be addressed in both planning studies and in actual implementation: Moderate start/stop times depends on hot/warm/cold status - typically 30 minutes to 2 hours+ Higher start up NO x levels and during steam turbine soak periods Some technology options and technology versions reduce time and extend load range at lower NO x levels Permits must reflect realities of start-ups and SCR warm up/temperature periods Limited turndown at efficient and low NO x levels (typically 65%+; some might be lower) Modest space Requires some additional rock removal and disposal from north east side of current units 1 to 3 Gas pressures required are higher, likely necessitating an on-site compressor Load swings and two shifting can be more readily followed than existing units, but can result in gas-electricity dispatch interface issues technical and economic implications Not necessarily consistent with current roughly 150 MW/day swing permissible under gas supply agreement at Burrard TGS Full load NO x at 2 to 5 ppm vd (at 15% O 2 ) at a higher efficiency is lower (comparable to about 4 to 10 ppm vd at 3% O 2 on Burrard TGS units) than existing Burrard TGS units on gas with SCR (17-25 ppm permit at 3% O 2 (benefit) Reduced start-up/shut-down, warm-up times and low load out-of-merit operating times may further reduce overall NO x emissions (benefit) 28 April 2008 RP Revision 1 Page 57 Page 160 of 215

161 Low load operation by Burrard TGS may increase NO x emissions per unit energy, but this is offset somewhat by lower volumetric emission rates at lower loads CCGT has modest water requirements for cooling from Burrard TGS inlet or fresh water from Lake Buntzen likely about 25%-30% per MWh of existing Burrard TGS units May allow more effective use in existing Burrard TGS steam units providing added flexibility (benefit) May, in the envisioned dispatch, require lower load, less efficient operation of Burrard TGS Units 4 to 6, but vastly offset by higher efficiency CCGT operation. Some opportunities for real optimizing of emissions, gas use, etc. (benefit) 6.2. Facility Description This section will describe the basic plant option and its layout, with brief descriptions of the major parts of the plant: GT HRSG Steam Turbine Environmental Controls Interface with existing facility Changes to existing facility Figure 6-1 Heavy Frame F Class CCGT (Ref: Siemens 501F Applications Overview 2004) The F class of gas turbines (i.e. GE701FA, Siemens SCG5000F, and Alstom GT24) form the basis for the case here. They are one of the leading gas turbines used in the electricity generation utility industry, typically producing between 170 to 200 MW per gas turbine machine plus about 50% more in steam turbine generation. There is a huge amount of CCGT 28 April 2008 RP Revision 1 Page 58 Page 161 of 215

162 experience, with most of the major difficulties well understood and addressed. They have a number of features well suited to this application: Moderate footprint Good efficiency (although less than newer, larger G or H class machines) Low dry low NO x burners available (9 ppm) and SCR systems are both well proven as industry BACT in different jurisdictions. In this case SCR as well as CO catalytic conversion is expected as BACT with some of the existing Burrard TGS SCR/ammonia infrastructure used Competitive marketplace several suppliers Available in outdoor (individual noise/weather) enclosures or indoor building applications Reasonable within confines of Burrard TGS site A single unit consisting of two F class generic gas turbine machines and 2 HRSGs and 1 steam turbine was selected for purposes of this study. This appeared to be optimal based on site space availability, maximum size based on system needs, minimal existing unit outage during construction and minimizing capital in an uncertain environment while providing spares for enhancing the availability/reliability of Units 4 to 6. Existing Burrard TGS Units 4 to 6 are assumed retained more or less as is. As the CCGT will not enter service until 2015 and Burrard TGS still needs to be a reliable supplier as per Task 1 and 2 report. Given this, much of the work and capital investment on Units 4 to 6 in Scenario 1 of the Task 1and 2 Report would apply in the years 2009 to After the CCGTs enter service, Units 4 to 6 are assumed to see minimal operation, but given the relative performance of Units 4 to 6 versus CCGTs that may not be the case and some further optimization between the two types of generation would logically follow. Existing Units 1 to 3 will also still need to be a reliable supplier as per Task 1 and 2 Report Scenario 3 until the CCGT enters service, assumed in this report to be Given this, much of the work and capital investment in Scenario 3 would apply in the years 2009 to Once the CCGT is operational, Units 1 to 3 can be decommissioned (the boilers may possibly be demolished) and parts used to maintain Units 4 to 6 minimizing further capital expenditure there. In the current configuration, Unit 1 is removed from service before the CCGT unit is complete to accommodate the new steam turbine. This could be for a year before the new CCGT unit s in service. If the outage is not deemed possible, then alternatively the CCGT could be built further east so as to leave the Unit 1 intact. This would also allow the second CCGT nit in Scenario 3 to be built completely in the space of Units 1 to 3 and not require the use of Unit 4 s steam turbine space Options Other options that were considered and might be considered further in more detailed evaluations include: 28 April 2008 RP Revision 1 Page 59 Page 162 of 215

163 Newer FB class machines similar to basic F class used here, but slightly larger and more efficient but not enough to change assessments herein Larger G and H class gas turbines - large size relative to the role and need suggested that they were not suitable despite higher efficiency and lower capital and OMA costs Single shaft 1x1x1 CCGT length of generation train and higher initial cost makes these likely not desirable Duct firing to boost the output of the steam cycle by about 50 to 100 MW (at fairly good incremental efficiencies and emission levels and at minimal incremental capital costs) Performance enhancements such as evaporative cooling of inlet air should be considered in more detailed evaluations. Evaporative cooling was assumed, but not in detail and others may also be desirable but were not necessary for this analysis to meet capacity needs 6.3. Operating Pattern BC Hydro provided a monthly operating pattern for a 3000 GWh/yr case for the current Burrard TGS configuration of 6 steam cycle units that was interpreted to arrive at a comparable pattern for Units 1 to 3 and Units 4 to 6. The pattern suggested 0 generation in March through June. It was also assumed that 1 unit of the synchronous condenser was required 90% of time and a second unit 25% of time. Figure 6-2 Scenario Current Configuration Monthly Load Pattern Scenario GWh/Year MW and GWh/Mo Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Max Capacity Available MW Month of Year Cooling Water Limited Av Capacity MW BC Hydro Model: GWh/Yr =2976 BC Hydro Model GWh/Mo Cooling Water Limited GWh/Yr= 2976 Cooling Water Limited GWh/Mo AV Daily Capacity Req MW 28 April 2008 RP Revision 1 Page 60 Page 163 of 215

164 A similar monthly pattern was used for the Scenario A2 CCGT 3000 GWh, except that the CCGT unit was essentially used as the primary generation source and the existing Burrard TGS Units 4 to 6 used for peaking. The result is that the CCGT unit essentially runs all the year at almost 100% load except March to June where they don t run at all. Existing Units 4 to 6 would run from 13% to 30% monthly capacity factor (about 50%-60% operating factor low load) from July to February and 0% in March to June. The pattern used is illustrated in Figure 6-3. It results in the CCGT producing about 2600 GWh/yr or about 75% of the generation and existing Burrard TGS Units 4 to 6 producing about 530 GWh or about 25% of the generation (plus about 1700 hours of synchronous condenser operation per unit after conversion kit added). The CCGT has a 56% ACF and 65% OF, and existing Burrard TGS Units 4 to 6 have a 14% ACF and 40% OF (up to 60% OF with synchronous condenser operation required). There is no limit on generation or generation capacity for Scenario A2 as a result of the current Effluent Permit restriction on cooling water availability and temperature. Figure 6-3 Scenario A GWh/Mo CCGT Generation by Month Scenario A2 - CCGT 3000 GWh/Year MW and GWh/Mo Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Max Capacity Available MW Cooling Water Limited Av Capacity MW Month of Year BC Hydro Model GWh/Mo BC Hydro Model: GWh/Yr =2976 Cooling Water Limited GWh/Mo Cooling Water Limited GWh/Yr= 2976 AV Daily Capacity Req MW Actual Generation GWh/Mo 28 April 2008 RP Revision 1 Page 61 Page 164 of 215

165 Figure 6-3a Scenario A GWh/Mo CCGT Generation by Month Scenario A GWh/Year CCGT GWh/Mo Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep GWh/Mo Units 4 to 6 BC Hydro Model GWh/Mo Month of Year AV Daily Capacity Req MW BC Hydro Model: GWh/Yr =2976 Series6 Cooling Water Limited GWh/Yr= 2976 GWh/Mo CCGT Units GWh/Mo Total Plant For the purposes of this study, this model is likely adequate. However, an initial assessment strongly suggests that actual operation would again likely tend to favour a somewhat more blended result with more partial steam turbine use at higher loads, where longer sustained runs are needed, and with the CCGT unit running more at high part load levels or possibly with one gas turbine out of service. This is, however, more in the realm of a system analyses than could be undertaken here Plant Layout Figure 6-4 illustrates the location of adding the CCGT at the right end (nominally the east end) of the plant where there appears to be adequate space to install it without disrupting plant operations and the potential for a relatively easy change-out to the existing switchyard. It does require significant rock removal in the area, but the encroachment on the SCR ammonia storage area should not be an issue. If necessary, the CCGT unit could be built slightly further east so that all of the CCGT is outside the existing building and operation of existing Unit 1 is not affected during construction. An alternative siting would be at the left or west end of the plant, but this involves issues with high water lines, land ownership, moving facilities, eliminating employee parking areas and major changes to switchyard connections. 28 April 2008 RP Revision 1 Page 62 Page 165 of 215

166 Construction logistics will be the major challenge to receive and manage the handling of the large CCGT equipment. There is, however, opportunity to use the water unloading ramp (if the equipment can be moved down the rather narrow transformer row, or through a landing at the east end of the plant or through the IOCO refinery road area. Figure 6-4 Heavy Frame CCGT Site Layout Figure 6-5 is a closer look at the layout. It is possible to see the extent of the excavation from the existing rock faces at the back and end of the Unit 1 transformer area. It is possible that a larger rock cut may be needed to accommodate construction logistics, but that will require detailed study. It is evident, given its closeness to the existing structure and to the elevated switchyard and SCR ammonia storage area that the stacks of the CCGT will have to be taller than the 30 to 40 meters typically used. In this study a 150 foot stack is assumed. It is also evident that some early changes will be needed to the existing natural gas, steam and ammonia supply lines that pass through or near the CCGT areas early in the project schedule. This could occur during a relatively short station outage for tie-ins during a summer outage period. In order to implement this solution, the following additions are required: 28 April 2008 RP Revision 1 Page 63 Page 166 of 215

167 Civil: New: Modified: Demolition: Mechanical: New: Modified: Electrical: New: Modified: Stacks; gas turbine building; main transformer enclosures; GT air intake Steam Turbine Foundation; switchyard reconfiguration (out of scope); SCR ammonia enclosure rock; Units 1 and 2 boiler and asbestos (options) Steam turbine and auxiliaries; gas turbines and auxiliaries; HRSGs and auxiliaries and piping; Boiler feedwater system; cooling water system Main Output transformers; Units station service transformers; HV switchgear; MCC and cabling Existing MCC and switchgear; switchyard reconfiguration Instrumentation and Control: New: New central DCS GTs ST, HRSG and auxiliaries Modified: Existing steam turbine DCS Figure 6-5 Close-Up of Heavy Frame CCGT Site Layout 28 April 2008 RP Revision 1 Page 64 Page 167 of 215

168 This concept is similar to that developed in the 1994 Sandwell/Stone & Webster report. The details unique to Burrard TGS are highlighted in two figures from that report presented as Figure 6-6 and Figure 6-7. The figures show that the air intake duct has to be routed underneath the existing plant crane rails and out the south side of the existing steam turbine powerhouse building and then onto the roof of the powerhouse. This will add some additional capital cost and also inlet pressure and hence a small MW derate. Figure 6-6 Heavy Frame CCGT Equipment Elevation Layout 28 April 2008 RP Revision 1 Page 65 Page 168 of 215

169 Figure 6-7 Heavy Frame CCGT Equipment Plan Layout 6.5. Schedule The Scenario A2 schedule for the installation of the heavy frame F Class SCGT option is illustrated in Figure 6-8. The In-Service date is Q4 of This is based on a three year CCGT order to In-Service timeline. The order placement date is Q Figure 6-8 Schedule Scenario A GWh/yr, 540 MW F Class CCGT 28 April 2008 RP Revision 1 Page 66 Page 169 of 215

170 6.6. Capital Cost The Scenario A2 capital cost is presented in Table 6-1. It is based on a review against Ontario lump sum, turnkey, EPC plant estimates, with adjustments for scope differences, price increases and existing facilities at Burrard TGS. There have been considerable price increases in major equipment, construction labour and commodity materials recently; hence prices tend to be higher than historic levels. The lump sum EPC pricing basis tends to result in higher direct costs and lower contingency and indirects than built up costs. They are reasonable compared to other built up estimates for similar sized conceptual plants for BC Hydro and others, recognizing that one generally pays a modest premium for a fixed price lump sum contract. Based on this, the estimate appears reasonable and likely to be +30%/-15%%. Table 6-2 presents the timeline assumed and a reasonable associated cashflow for analyses purposes. There is considerable room for variation in the cashflow depending on market and contracting approaches. Table 6-1 Capital Cost Scenario A GWH/yr 540 MW F Class CCGT 28 April 2008 RP Revision 1 Page 67 Page 170 of 215

171 Table 6-2 Timeline and Cashflow Scenario A GWh/yr, 540 MW F Class CCGT 6.7. OMA Cost The heavy frame CCGT OMA costs are illustrated in Table 6-3. It is assumed that another 27 incremental staff are required beyond those for just Burrard TGS Units 4 to 6. In some classic stand-alone CCGT plants, 30 to 40 staff are used. No initial unit start-up power was charged to the facility, although that is often done. Table 6-3 CCGT OMA also provides two types of OMA for information purposes. The base case is the No Risk Mitigation case: the owner has no Customer Service Agreement (CSA) or Long Term Service Agreement (LTSA) with an OEM for specific 20 year parts and service. The second is a Risk Mitigation case: a CSA or LTSA is established for a given period and operating pattern and those costs covered are paid at a fixed rate over the period. For a base load/intermediate load CCGT, the difference between the cases is modest and other factors influence any decision --- a hybrid is sometimes selected. Risk and accounting flexibility may play a role as well. Care must still be taken in applying these costs as they (in absolute $ terms or in Fixed and Variable Cost terms) can still vary significantly if the basis is changed to suit specific circumstances and arrangements. 28 April 2008 RP Revision 1 Page 68 Page 171 of 215

172 Table 6-3 OMA Costs Scenario A GWh/yr, 540 MW F Class CCGT 6.8. Cashflow Table 6-4 presents the Cashflow for Scenario A2 CCGT Cashflow (2007 Cdn$). It provides a capital and OMA cashflow from FY2008 through FY2028. It assumes that Units 1 through 6 (typically 25% generation from U1-3 and 75% from U4-6) operate until the CCGT unit comes on line in Q4 FY2014, at which time the pattern in Section 6.3 is used. The existing unit cashflow used is basically the current investment program (Scenario 0) adjusted to reflect the low Units 4 to 6 ACF/OF after the CCGT comes on stream. This lower Unit 4 to 6 OMA/capital stream is also consistent with the fact that spare equipment from Units 1 to 3 can be retained to support Units 4 to April 2008 RP Revision 1 Page 69 Page 172 of 215

173 Table 6-4 Cashflow Costs Scenario A2 - Heavy Frame F Class CCGT 28 April 2008 RP Revision 1 Page 70 Page 173 of 215

174 Table 6-4 (Continued) Cashflow Costs Scenario A2 - Heavy Frame F Class CCGT 6.9. Environment This section will address the environmental emissions associated with the facility and it s compatibility with existing and likely future new generation permits Air Environment The emissions rates for the CCGT unit, assuming that the unit turndown is managed to minimize NO x and CO emissions, could result in the following levels of emissions, allowing for SCR and CO catalyst reduction of NO x and CO. 28 April 2008 RP Revision 1 Page 71 Page 174 of 215

175 Table 6-5 Scenario A2 Optimized Emission Rates - Heavy Frame F Class CCGT The NO x and CO emissions could, however, be much higher at low loads if the SCR and CO catalysts are not sized appropriately and ammonia supplied in sufficient quantities such that the system cannot inject enough ammonia or if it falls below an effective temperature. Values as high as the following could result. Table 6-6 Scenario A2 Potential Emission Rates - Heavy Frame F Class CCGT These are based on emissions after the SCR of the following volumetric emission levels versus single gas turbine unit load levels. Some systems may not have this effect and any purchase should be aware of this especially if low load and frequent starts are anticipated. Table 6-7 Scenario A2 Potential Emission Rates (Volumetric) - Heavy Frame F Class CCGT Assuming the gas turbines were brought down in parallel such that high NO x and CO emissions result at the 50% load point and even with 80% NO x and CO reduction in the catalyst, the values below would result. The following is based on the SCR being fully operative and effective at low loads below 50%. 28 April 2008 RP Revision 1 Page 72 Page 175 of 215

176 Table 6-8 Scenario A2 Single Unit/Parallel Emission Rates - Heavy Frame F Class CCGT This approach where the gas turbines are turned down in parallel are reflected in Figure 6-9. Figure 6-9 Scenario A2 Single Unit Emission Rates vs. Load - Heavy Frame F Class CCGT In fact there are a number of ways to reach some loads in the 25% to 50% load range as shown in Figure In optimizing emissions and efficiency, one may turndown the gas turbines in parallel to get the curves in Figure The desirable intent would be to get as close to the optimum curve in Figure 6-12 as possible. 28 April 2008 RP Revision 1 Page 73 Page 176 of 215

177 Figure 6-10 Scenario A2 - Possible Operating Points Emissions Data 28 April 2008 RP Revision 1 Page 74 Page 177 of 215

178 Figure 6-11 Scenario A2 - Parallel Turndown Emissions Curve Scenario A GWh/Yr CCGT Smoothed Emissions vs % Load Emission Rate NOx, CO, UHC, SO2, NH3 g/kwh CO2 Emission Rate g/kwh % 20% 40% 60% 80% 100% 120% Net CCGT Load MW NOx CO UHC SO2 NH3 CO April 2008 RP Revision 1 Page 75 Page 178 of 215

179 Figure 6-12 Scenario A2 - Optimal Emissions Curve Part of the effect of differences in emission levels is due to the effect of part load heat rate or efficiency. The Net Heat rate (GJ/MWh) as a function of % of full load (MCR) power for both the CCGT unit and the existing Units 4 to 6 is shown below in Figure The figure is based on 20 o C ambient conditions. The CCGT is affected much more by ambient temperature than the existing CSC units. 28 April 2008 RP Revision 1 Page 76 Page 179 of 215

180 Figure 6-13 Scenario A GWh/yr CCGT Heat Rate vs. Load vs. Existing Units 4 to Scenario A GWh/Yr CCGT Unit Heat Rate vs % MCR Load Net Ht Rate GJ/MWhn % 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100% % of MCR CCGT Units 4 to 6 The emission rates and annual emission values for the current CSC units as part of Scenario 2 (3000 GWh/yr, Current Configuration) are shown in Figure Figure April 2008 RP Revision 1 Page 77 Page 180 of 215

181 Scenario GWh/yr - Existing Units Emissions The range provided reflects potential values due to such things as the condition of equipment (the SCR and the combustion equipment) and other variables such as the sulphur in the natural gas. Other variations such as operating pattern and deterioration are smaller and usually within +/-5 to10%. They do not however affect the station s ability to meet current permit values. Some reductions are also achievable through improvements (airpreheater seals and turbine efficiency). 28 April 2008 RP Revision 1 Page 78 Page 181 of 215

182 Corresponding emissions rate and annual emissions data for the Alternative Configuration Scenario A2, 3000 CCGT are shown in Figure The Alternative Configuration includes both the CCGT emissions and those from the generation of the remaining CSC Units 4 to 6. Figure 6-15 Scenario A GWh/yr CCGT and Units 4 to 6 Emissions From a review of the Figures, the following observations can be drawn: CO 2 and SO 2 emissions are substantially reduced on a g/kwh and annual basis, primarily due to the efficiency difference between a CCGT and a CSC 28 April 2008 RP Revision 1 Page 79 Page 182 of 215

183 NO x emissions are substantially reduced on a g/kwh and annual basis, both due to the efficiency difference between a CCGT and a CSC and the lower outlet emission level The existing Air Emission Permit standards will be compromised by the CCGT replacement of three CSC unit. However, as noted in section 2 of the report, new Air Emission Permit standards may be imposed as part of the CCGT permitting process; Ammonia emissions are similar because the ammonia slip levels of the SCR from both the CCGT unit and existing units is similar on a g/kwh basis; Any new permits need to address the impact of the existing unit operations and uncertainty over the split in generation Water Environment Fresh water consumption in Scenario A2 for the CCGT unit will be less than that for a CSC unit since only about 30% to 40% of the HRSG/boiler blowdown and demineralized water make-up is required. The gas turbine and generator itself have minimal lube oil cooler water requirements. If inlet evaporative coolers are used in summer to minimize ambient temperature derates, it s fresh water consumption may be significant, up to about 60 USGPM = 135,000 USGPD or about 0.55 MML/day if for 24 hrs, which is unlikely. Most of the year water use would be significantly less. The quantities needed for continuing to operate CSC Units 4 to 6 would remain the same for the generation levels being produced. The overall quantities of fresh water use should be significantly less than the current Lake Buntzen consumption, but care should be taken in accepting any permit reduction until a more detailed assessment is made. As can be seen from Figure 6-3 in Section 6-3, cooling water limits should not be an issue. A CCGT uses about 40% of the cooling water per total MW that a CSC does. Hence, replacing half of the existing station with a CCGT unit and preferentially running the CCGT unit means there is plenty of cooling water under the existing Effluent Permit as indicated in Figure 6-3. Care must be taken, however, with any permit alteration to ensure that the new permit or amended existing Effluent Permit allows for the uncertainty in the generation split between the CCGT and the existing Units 4 to Other Environment Noise is another primary environmental impact and will require significant effort in the given environment. The primary impact will be on plant performance, costing up to 1% reduction in capacity and 1% in performance (i.e. 1% higher heat rate) Performance Figure 6-16 illustrates the heat balance for Scenario A2. It provides the basic information needed to understand the fuel and air inflows and the electricity generation. It also provides the new and clean heat rate defined as a Low Heating Value (LHV) heat rate. This is most often how the gas turbine industry provides heat rate or efficiency. It must, however, be converted to a Higher Heating Value (HHV) basis, in order to use it with fuel pricing which is usually quoted on a HHV basis. For natural gas, multiply LHV heat rate by 1.11 to get the HHV heat rate. For the efficiency, divide the LHV efficiency by 1.11 to get the HHV efficiency 28 April 2008 RP Revision 1 Page 80 Page 183 of 215

184 Figure 6-16 Scenario A GWh - CCGT Performance Information New and Clean Note: To convert LHV to HHV, multiply by 1.11 In developing plans, one must also address the difference between new and clean and typical performance. The gas turbines in a CCGT tend to get fouled with contaminants from the air and as a result experience both a permanent degradation and a temporary/recoverable degradation. The temporary degradation will be recovered when the machines are washed either using on-line techniques or through periodic off-line washes. This degradation of both capacity and heat rate (i.e. increased heat rate or reduced efficiency) can be in the order of 2% or more depending on the environment. Further, there can be other factors which cause a higher than expected average MCR heat rate and lower than expected MCR capacity. Ambient temperature and relative humidity also have an effect on generation capacity and heat rate. Capacity tends to decrease with higher ambient temperature and heat rate rises slightly. This is less significant than for the SCGT since the HRSG and steam turbine in a CCGT will 28 April 2008 RP Revision 1 Page 81 Page 184 of 215

185 recover some of the gas turbines energy losses. It is also possible to employ front end gas turbine cooling and backend HRSG duct firing to recover some of the summer capacity losses, although with some degradation in overall efficiency. Part load operation also has a significant effect on efficiency at loads below 50 to 70%. Figure 6-16a Scenario A GWh - CCGT Performance Information New and Clean Note: To convert LHV to HHV, multiply by 1.11 The base CCGT design incorporates evaporative inlet air cooling to reduce the impact of high summer ambient temperatures on output and efficiency. Figure 6-17 illustrates the impact on the Base output and heat rate throughout the year at Burrard TGS, as function of average monthly ambient temperature and relative humidity (Environment Canada data for Port Moody Glenayre). Figure April 2008 RP Revision 1 Page 82 Page 185 of 215

186 Scenario A GWh - CCGT Performance vs. Ambient Burrard TGS Conditions 105.0% 104.0% 103.0% Burrard CCGT Performance % of Base MWn and Base Heat Rate 102.0% 101.0% 100.0% 99.0% 98.0% 97.0% 96.0% 95.0% Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Month % of Base Capacity % Base Heat Rate Fuelling Cost: The Base new and clean CCGT capacity (MW) and efficiency (kj/kwh on an HHV basis) at ISO conditions of 20 o C and 60%RH is nominally 550 MW and 6963 kj/kwh (6,600 BTU/kWh). This is a generic value since 3 F class machines from various vendors can produce anywhere from 515 to 600 MW. As noted, the ambient temperature will affect summer and winter capacities and heat rates (and hence generation fuelling costs proportional to the heat rate curve). Assuming an average 5% degradation and other losses allowance, the more typical MCR heat rate value becomes 7,300 kj/kwh (7,000 BTU/kWh). Assuming a $6/MMBTU (HHV) gas cost, the fuelling cost would be $44/MWhe. 28 April 2008 RP Revision 1 Page 83 Page 186 of 215

187 7. SCENARIO A GWH/YR, 1100 MW CCGT - REPLACE BURRARD TGS GENERATION WITH BASELOAD CCGT 7.1. General In Scenario A3, all Burrard TGS units (Units 1 to 6) are replaced with 2 new gas turbine combined cycles (CCGT) units totaling between 1000 and 1200 MW. Each MW CCGT unit would consist of 2 heavy frame F Class gas turbines ( MW) and 2 Heat Recovery Steam Generators (HRSG) and 1 steam turbine ( MW). The first CCGT would likely be added as per Scenario A2, located east of Units 1 to 3 powerhouse and boiler and the Unit 1 steam turbine replaced with a new steam turbine. The second CCGTs two gas turbine/hrsgs would be located in the space of existing Units 2 and 3 after the demolition of boilers 1 to 3 and reconstruction of steam turbine areas of Units 2 and 3 to accommodate the new gas turbines. The second CCGTs steam turbine would be located in the space of existing Unit 4 steam turbine (perhaps Unit 4 steam turbine may be used and repowered if its condition indicates long life). The second CCGT unit will require a delay of at least a year from the installation of the first CCGT unit to avoid any capacity reduction from Burrard TGS. An option would be to install the second CCGT at the west end of the plant, but space limits, high water lines and changes to infrastructure may make this undesirable. It should, however, be left as an option in any future construction RFP s. The scheme would re-utilize a lot of existing site infrastructure cooling water intake and delivery, administration building, cranes, ammonia storage. Existing Units 5 and 6 would be retained in the interim period between the first and second CCGT in-service and subsequently retired. Existing Units 2 to 3 will have to be maintained until the first CCGT unit is in-service. Some initial spares may be available from Unit 1 steam turbine. After the first CCGT in-service Units 1 to 3 will provide spares for Units 4 to 6 for reliability purposes during the construction period for the second CCGT unit. Some upgrades on Units 1 to 3 and Units 4 to 6 will be necessary in the short term to allow them to provide reliable service until the CCGTs enter service in 2014 to Specific to this case, the following were assumptions: Similar to Scenario A2 and retain Units 5 and 6 during second CCGT unit construction minimize capacity supply disruption during implementation retention of at least existing capacity is necessary, but planning optimization may lead to less installed capacity given the better generation response flexibility of the new generation 28 April 2008 RP Revision 1 Page 84 Page 187 of 215

188 NO x emissions (and others) must meet BACT standards currently 3 to 5ppm with Selective Catalytic reduction (SCR) similar to that employed on existing Burrard TGS CSC steam turbine units Existing facility permit levels for NO x, water usage, etc. must not be compromised New permits must allow for some form of start-up/shut-down allowances and will probably impose limits on those allowances similar to those proposed for the SE2 CCGT New CCGT permitted emissions limits will be similar to those identified with the proposed SE2 660 MW CCGT which was to be sited in Sumas, Washington State, in the same airshed as Burrard TGS, which are achievable provided transition allowances are made Gas supply will be optimized, including dispatch arrangements, to allow unhindered unit dispatch Noise will be approximately 58 dba at plant boundary Stacks will be nominally 150 feet for study purposes, but modeling and impingement on existing unit structures may necessitate taller stacks up to slightly higher than existing boiler structures This CCGT option has the same several positive and negative features identified for Scenario A Facility Description The CCGT portion of the facility is the same as for Scenario A2 described in Section 6.2. The primary difference is in the changes to the existing facility. Existing Burrard TGS Units 5 to 6 are assumed retained more or less as is until completion of the second CCGT unit, except for the period where Unit 4 s steam turbine may be modified or replaced. The CCGT will not enter service until late 2015 or early 2016 and Burrard TGS still needs to be a reliable supplier as per Task 1 and 2 Report Scenario 3. Much of the work and capital investment on Units 4 to 6 in Scenario 3 of the Task 1 and 2 Report would apply in the years 2009 to After the first CCGTs enter service, Units 4 to 6 are assumed to see minimal operation, and then to shut down upon completion of the second CCGT. Existing Units 1 to 3 will also still need to be a reliable supplier as per the Task 1 and 2 Report Scenario 3 until Given this, much of the work and capital investment in Scenario 3 would apply in the years 2009 to Given that much cannot be achieved until 2010, care must be taken in what work is done versus an enhanced maintenance and monitoring program. Once the first CCGT is operational, Units 1 to 3 are decommissioned and the boilers and other equipment areas needed for the second CCGT unit is demolished. Some parts will be used to maintain Units 4 to 6 minimizing further capital expenditure there. 28 April 2008 RP Revision 1 Page 85 Page 188 of 215

189 Options As in Scenario A2, other options that were considered and might be considered further in more detailed evaluations include: The options identified in Section for Scenario A2 The repowering of Unit 4 steam turbine versus replacement to minimize overall costs and delays in second CCGT in-service definite possibility The placement of the second CCGT at the west end of the site or in the area of the current warehouse space issues 7.3. Operating Pattern BC Hydro provided a monthly operating pattern for a 6000 GWh/yr case for the current Burrard TGS configuration of 6 steam cycle units (Figure 7-1) The pattern suggested all six Burrard TGS units were fairly base loaded from September through February at about 60 to 75% monthly capacity factor, and that in April through September 5 units were similarly base loaded each of the six units was out of service for one month during the period for maintenance. Figure 7-1 Operating Pattern - Scenario GWh/yr, Current Configuration Scenario GWh/Year MW and GWh/Mo Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Max Capacity Available MW Cooling Water Limited Av Capacity MW BC Hydro Model GWh/Mo Cooling Water Limited GWh/Mo Actual generation GWh/Mo Month of Year BC Hydro Model: GWh/Yr =6112 Cooling Water Limited GWh/Yr= 5872 Actual Generation GWh/Yr= 5830 A similar monthly pattern was used for the Scenario A GWh CCGT, except for four months only one gas turbine was out of service and for one to two months when a steam turbine 28 April 2008 RP Revision 1 Page 86 Page 189 of 215

190 was out of service. When a steam turbine is removed from service for an extended maintenance period, which shouldn t happen very often, it effectively takes out the entire 540 MW CCGT unit (shown in Figure 7-2 as a worst case twice in June and September but realistically only one would occur in any given year and not every year). In those two months, the 540 MW capacity loss might be an issue, but for study purposes it is expected that this would be managed easily. Of course, the whole scheme is much more complex since the outage pattern of the gas turbine and steam turbines will reflect their actual operating pattern and maintenance schedules. Figure 7-2 Operating Pattern Scenario GWh/yr, 1100 MW CCGT Scenario A GWh/Year MW CCGT MW and GWh/Mo Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Max Capacity Available MW Month of Year Cooling Water Limited Av Capacity MW BC Hydro Model: GWh/Yr =6112 BC Hydro Model GWh/Mo Cooling Water Limited GWh/Yr= 5872 Cooling Water Limited GWh/Mo Actual Generation GWh/Yr= 5830 CCGT Generation GWh/Mo The CCGTs run all the year at essentially 60% to 75% monthly capacity factor (and 80-90% operating factor) and at 100% in the month when the other CCGT is on a steam turbine outage. The pattern used is illustrated in Figure 7-2. It results in each CCGT unit producing about 3000 GWh/yr or about 50% of the generation. There is no synchronous condenser operation as the generating units are assumed to produce enough VARS. For the purposes of this study, this model is likely adequate for planning information purposes. Any more detailed evaluation is in the realm of a system analyses, not the intent herein. Contingency plans for a steam turbine loss would be critical. 28 April 2008 RP Revision 1 Page 87 Page 190 of 215

191 7.4. Plant Layout Figure 7-3 illustrates the location of adding the CCGTs. The first CCGT unit is at the right end (nominally the east end) of the plant as per Scenario 2A. The second CCGT unit is placed in the spaces of existing Units 2 and 3 and uses the space of Steam Turbine #4 for its new steam turbine. There appears to be adequate space at the east end of the plant to install the first CCGT unit without disrupting plant operations and to provide the potential for a relatively easy change-out to the existing switchyard. It does require significant rock removal in the area, but the encroachment on the SCR ammonia storage area should not be an issue. Figure 7-3 Scenario A3 - Heavy Frame CCGT Site Layout The location of the second CCGT unit is of concern since it is between the first CCGT unit and operating units in the existing plant. An alternative siting would be at the left or west end of the plant, but this involves issues with high water lines, land ownership, moving facilities, eliminating employee parking areas and major changes to switchyard connections. It may be that a second CCGT facility is not particularly viable at this site without the complete prior demolition of some 28 April 2008 RP Revision 1 Page 88 Page 191 of 215

192 of the existing facility and loss of some generation capability in the interim specifically Units 1 to 3. Construction logistics will be the major challenge, particularly for the second CCGT unit. To receive and manage the handling of the large CCGT equipment will be difficult for the first CCGT unit, but there is opportunity to use the water unloading ramp (if the equipment can be moved down the rather narrow transformer row, through a landing at the east end of the plant or through the IOCO refinery road area). The second CCGT unit construction, however, involves major constructability challenges and will require detailed studies to implement economically and safely. Figure 7-4 is a closer look at the layout. It is possible to see the extent of the excavation from the existing rock faces at the back and end of the Unit 1 transformer area. It is possible that a larger rock cut may be needed to accommodate construction logistics, but that will require a detailed study. It is evident, given its closeness to the existing structure, to the elevated switchyard and SCR ammonia storage area that the stacks of these CCGTs will have to be taller than the 30 to 40 meters typically used. In this study a 150 foot stack is assumed. It is also evident that some early changes will be needed to the existing natural gas, steam and ammonia supply lines that pass through or near the CCGT areas early in the project schedule. This could occur during a relatively short station outage for tie-ins during a summer outage period. Figure 7-4 also shows how difficult the retrofit of the second CCGT unit may be. In order to implement this solution, the following additions are required: Civil: New: Stacks; gas turbine building; main transformer enclosures; GT air intake Modified: Steam Turbine Foundation; switchyard reconfiguration (out of scope) Demolition: SCR ammonia enclosure rock; Units 1 and 2 boiler and asbestos (options) Mechanical: New: Modified: Steam turbine and auxiliaries; gas turbines and auxiliaries; HRSGs and auxiliaries and piping Boiler feedwater system; cooling water system Electrical: New: Modified: Main Output transformers; Units station service transformers; HV switchgear; MCC and cabling Existing MCC and switchgear; switchyard reconfiguration 28 April 2008 RP Revision 1 Page 89 Page 192 of 215

193 Figure 7-4 Scenario A3 - Close-Up of Heavy Frame CCGT Site Layout Instrumentation and Control: New New central DCS GTs ST, HRSG and auxiliaries Modified: Existing steam turbine DCS 7.5. Schedule Scenario A3, 6000 GWh/yr, 1100 MW CCGT The Scenario A3 schedule for the installation is presented in Figure 7-5. The first CCGT inservice is Q as per Scenario A2. The second CCGT in-service is Q This is based on a three year CCGT order to in-service timeline and one year between the first and second CCGT, as well as an order placement date of Q April 2008 RP Revision 1 Page 90 Page 193 of 215

194 Figure 7-5 Schedule Scenario A3 2 Heavy Frame F Class CCGT Units 7.6. Capital Cost The Scenario A3 capital cost is presented in Table 7-1 and is based on the same premise as Scenario 2 in Section 6.6. Table 7-2 presents the timeline assumed and a reasonable associated cashflow for analyses purposes. There is considerable room for variation in the cashflow depending on market and contracting approaches. 28 April 2008 RP Revision 1 Page 91 Page 194 of 215

195 Table 7-1 Capital Cost Scenario A3 2 Heavy Frame F Class CCGT Units 28 April 2008 RP Revision 1 Page 92 Page 195 of 215

196 Table 7-2 Timeline and Cashflow Scenario A3 2 Heavy Frame F Class CCGT Units 7.7. OMA Cost The heavy frame CCGT OMA costs are illustrated in Table 7-3. It is assumed that 43 staff are required. No initial unit start-up power was charged to the facility, although that is often done. Table 7-3 CCGT OMA also provides two types of OMA for information purposes. The base case is likely the Risk Mitigation case: the owner has a comprehensive Customer Service Agreement (CSA) or Long Term Service Agreement (LTSA) with an OEM for specific 20 year parts and service. The second is a No Risk Mitigation case: no CSA or LTSA is established for a given period and operating pattern and those costs covered are paid for at a fixed rate over the period. For a base load, multi-unit CCGT installation, the difference between the cases may be significant and other factors influence any decision --- a hybrid may also be a better choice. Risk and accounting flexibility may play a role as well. Care must still be taken in applying these costs as they (in absolute $ terms or in Fixed and Variable Cost terms) can still vary significantly if the basis is changed to suit specific circumstances and arrangements. 28 April 2008 RP Revision 1 Page 93 Page 196 of 215

197 Table 7-3 OMA Costs Scenario A3-2 Heavy Frame F Class CCGT Units 7.8. Cashflow Table 7-4 presents the cashflows for Scenario A3 (2007 Cdn$). It provides a capital and OMA cashflow from FY2008 through FY2028. It assumes that Units 1 through 6 (typically 25% generation from U1-3 and 75% from U4-6) operate until the first CCGT unit comes on line in FY2014 and then 25% of generation from existing Units 4 to 6 until the second CCGT comes on line, at which time the pattern in Figure 7-5 is used. The existing unit cashflow used is basically the current investment program (Scenario 0) adjusted to reflect the limited life. This lower existing unit OMA/Capital stream is also consistent with the fact that spare equipment from Units 1 to 3 is retained for interim use in Units 4 to April 2008 RP Revision 1 Page 94 Page 197 of 215

198 Table 7-4 Cashflow Costs Scenario A3 2 Heavy Frame F Class CCGT Units 28 April 2008 RP Revision 1 Page 95 Page 198 of 215

199 Table 7-4 (Continued) Cashflow Costs Scenario A3 2 Heavy Frame F Class CCGT Units 7.9. Environment This section will address the environmental emissions associated with the facility and it s compatibility with existing and likely future new generation permits Air Environment The same issues around SCR and CO catalyst emissions rates for the Scenario A2 CCGT units in Table 6-5 through Table 6-8 would apply to Scenario A3 CCGT units. The possible combinations of emissions for various approaches to Unit load reduction management are repeated in Figure April 2008 RP Revision 1 Page 96 Page 199 of 215

200 Figure 7-6 Potential Emission Rate Optimization Scenario A3 2 Heavy Frame F Class CCGT Units The optimum approach, one extreme, is illustrated in Figure April 2008 RP Revision 1 Page 97 Page 200 of 215

201 Figure 7-7 Optimum Reduced Load Emission Rate Scenario A3 2 Heavy Frame F Class CCGT Units The other extreme using a parallel reduction path is shown in Figure April 2008 RP Revision 1 Page 98 Page 201 of 215

202 Figure 7-8 Parallel Reduced Load Emission Rate Scenario A3 2 F Class CCGT Units Part of the effect of differences in emission levels is due to the effect of part load heat rate or efficiency. The Net Heat rate (GJ/MWh) as a function of % of full load (MCR) power for both the two CCGT units and the existing Units 4 to 6 is shown below in Figure 7-9. The figure is based on 20 o C ambient conditions. The CCGTs are affected much more by ambient temperature than the existing CSC units. 28 April 2008 RP Revision 1 Page 99 Page 202 of 215

203 Figure 7-9 Scenario A GWh/yr CCGT Heat Rate vs. Load vs. Existing Units 4 to Scenario A GWh/Yr CCGT Unit Heat Rate vs % MCR Load Net Ht Rate GJ/MWhn % 5% 10% 15% 20% 25% 30% 35% 40% 45% 50% 55% 60% 65% 70% 75% 80% 85% 90% 95% 100% % of MCR CCGT Units 4 to 6 The emission rates and annual emission values for the current CSC units are shown in Figure Corresponding emissions rate and annual emissions data for the Alternative Configuration Scenario A3, 6000 CCGT, is shown in Figure Unlike Scenario A2, Scenario A3 only has CCGT emissions in the totals. 28 April 2008 RP Revision 1 Page 100 Page 203 of 215

204 Figure 7-10 Scenario GWh/yr Current Configuration Emissions Per Month and Annually As noted previously, a range of values is possible depending on the condition of equipment such as the SCR and the combustion equipment and on things such as the sulphur in the natural gas. Other variations such as operating pattern and deterioration are smaller and usually within +/-5 to 10%. A range is provided in annual emissions that reflects the potential 28 April 2008 RP Revision 1 Page 101 Page 204 of 215

205 differences. They do not however affect the station s ability to meet current permit values. Some reductions are also achievable through improvements (airpreheater seals and turbine efficiency). Figure 7-11 Scenario A GWh/yr CCGT Emissions Per Month and Annually From a review of the Figures, the following observations can be drawn: 28 April 2008 RP Revision 1 Page 102 Page 205 of 215

206 CO 2 and SO 2 emissions are substantially reduced on a g/kwh and annual basis, primarily due to the efficiency difference between a CCGT and a CSC; NO x emissions are substantially reduced on a g/kwh and annual basis, both due to the efficiency difference between a CCGT and a CSC and the lower outlet emission level; No existing Air Emission Permit limits will be compromised by the two CCGT unit replacement of the six existing CSC Units. However, as noted in section 2 of the report, new Air Emission Permit standards and limits may be imposed as part of the CCGT permitting process; Ammonia emissions are similar because the ammonia slip levels of the SCR from both the two CCGTs and existing Units are similar on a g/kwh basis; Any new permits need to address the impact of the existing unit operations and uncertainty over the split in generation Water Environment Fresh water consumption in Scenario A3 for the CCGT units will be less than for the six CSC Units since only about 30% to 40% of the HRSG/boiler blowdown and demineralized water make-up is required. The gas turbine and generator itself have minimal lube oil cooler water requirements. If inlet evaporative coolers are used in summer to minimize ambient temperature derates, the two CCGTs fresh water consumption may be significant, up to about 120 USGPM = 270,000 USGPD or about 1.0 MML/day if for 24 hrs, which is unlikely for a whole day. For most of the year, water use would be significantly less. The overall quantities of fresh water use should be significantly less than the current Lake Buntzen consumption, but care should be taken in accepting any permit reduction until a more detailed assessment is made. As can be seen from Figure 7-1 and Figure 7-2 in Section 7-3, cooling water limits should not be an issue. A CCGT uses about 40% of the cooling water per total MW that a CSC does. Hence, replacing the existing station with two CCGTs as a base load station means there is plenty of cooling water under the existing Effluent Permit. Care must be taken, however, with any permit alteration to ensure that the new or amended existing Effluent Permit allows for the uncertainty in the generation pattern of the two CCGT units Other Environment Noise is another primary environmental impact and will require significant effort in the given environment. The primary impact will be on plant performance, costing up to 1% reduction in capacity and 1% in performance (i.e. 1% higher heat rate) Performance: Figure 7-12 illustrates the heat balance for Scenario A3. The same comments identified for Scenario A2 in Section 6.10 around clean and new and Lower Heating Value LHV versus HHV apply here. Ambient temperature and relative humidity also have an effect on generation capacity and heat rate. Capacity tends to decrease with higher ambient temperature and heat rate rises slightly. This is less significant than for the SCGT since the HRSG and steam turbine in a CCGT will recover some of the gas turbines energy losses. It is also possible to employ front end gas 28 April 2008 RP Revision 1 Page 103 Page 206 of 215

207 turbine cooling and backend HRSG duct firing to recover some of the summer capacity losses, although with some degradation in overall efficiency. Part load operation also has a significant effect on efficiency at loads below 50 to 70%. Figure MW CCGT Performance Information New and Clean Note: To convert LHV to HHV, multiply by April 2008 RP Revision 1 Page 104 Page 207 of 215

208 Figure 7-12 (Continued) 1100 MW CCGT Performance Information New and Clean Note: To convert LHV to HHV, multiply by 1.11 As in Scenario A2, the base CCGT design incorporates evaporative inlet air cooling to reduce the impact of high summer ambient temperatures on output and efficiency. Figure 7-13 illustrates the impact on the Base output and heat rate throughout the year at Burrard TGS, as a function of average monthly ambient temperature and relative humidity (Environment Canada data for Port Moody Glenayre). 28 April 2008 RP Revision 1 Page 105 Page 208 of 215