Schedule 2 TECHNICAL INFORMATION

Schedule 2 TECHNICAL INFORMATION This document is intended to provide context to the Haida Gwaii Request for Expressions of Interest (RFEOI) for the potential electricity supply opportunity for clean electricity on the Haida Gwaii North Grid. Respondents should review the variability of demand on the North Grid in order to present a project solution that will meet the service area needs as outlined in this document. The information provided is indicative only based on recent historical data, and is not intended to be exhaustive; rather, the information is intended to assist the Respondent in establishing the potential opportunity for electricity supply. A project will only be able to supply electricity for the actual demand (e.g., BC Hydro only requires as much electricity as the system needs) and must operate in conjunction with the existing diesel generation to provide consistent and reliable power, and thus must be sized according to the nature of the dynamic load. 1. OVERVIEW OF DISTRIBUTION/GENERATION SYSTEM BC Hydro supplies electricity to Haida Gwaii via two separate, unconnected distribution systems: the North Grid and the South grid. The RFEOI is for projects interconnected to the North Grid only. The North Grid on Haida Gwaii supplies Masset and Old Masset, and the surrounding area as far south as Port Clements. The Masset diesel generation system (the MAS DGS ) is comprised of six diesel generators with a combined capacity of 12.545 MW with the following combination of stationary, road mobile and semi-mobile units 1 : Table 1: MAS DGS current fleet Stationary Generators Road Mobile Generators Semi-Mobile Generators MAS G1 2.865 MW M172 0.85 MW M125 2.50 MW MAS G2 2.865 MW M180 0.60 MW MAS G3 2.865 MW In 2014, for improved fleet optimization it is anticipated that the MAS DGS will comprise of five diesel generators with a combined capacity of 10.445 MW with the following combination of stationary and mobile units: Table 2: MAS DGS planned 2014 units Stationary Generators MAS G1 2.865 MW MAS G2 2.865 MW MAS G3 2.865 MW Road Mobile Generators M165 1.00 MW M172 0.85 MW The MAS DGS is comprised of two 25 kv distribution feeders: MAS 25F51 serves Masset and Old Masset with approximately 40 km of overhead line (16 km of 3-phase; 24 km of single-phase), and MAS 25F52 serves Port Clements with approximately 58 km of overhead distribution line (50 km of 3-phase; 8 km of single-phase). 1 Current as of September 2012 but may change as per operational requirements. Issued October 18, 2012 1

A single line diagram of the MAS DGS and distribution operating diagrams for MAS 25F51 and MAS 25F52 are available upon request. 2. TECHNICAL INFORMATION ON THE OPPORTUNITY 2.1 Haida Gwaii North Grid Historical Electricity Supply The characteristics of historical electrical energy load (total generation from generators including station service and losses) on the North Grid of Haida Gwaii for January 2001 to July 2012 are shown in Table 3 and graphically represented in Chart 1 and Chart 2. Note that 2012 contains incomplete data. Chart 1 displays the data from Table 3 by year. For example, in 2010, the average monthly generation (black diamond) was 2,234 MWh whereas the maximum monthly generation was 2,755 MWh (range bar) and the minimum monthly generation was 1,798 MWh (range bar). Similarly, Chart 2 displays the data from Table 3 by month. For example, in February (month 2), the average generation over the 2001-12 period was 2,308 MWh (black diamond) whereas the maximum generation was 2,555 MWh (range bar) and the minimum generation was 2,126 MWh (range bar). Table 3: MAS DGS total energy supplied (MWh) Jan. 2001 July 2012 Year January February March April May June July August September October November December Totals 2001 2,358.82 2,168.32 2,320.34 2,091.39 2,100.17 1,839.52 1,914.94 1,741.23 1,831.66 2,160.34 2,278.58 2,494.41 25,299.70 2002 2,418.97 2,196.64 2,472.01 2,173.74 2,080.18 1,783.02 1,879.20 1,837.22 1,873.98 2,065.03 2,148.66 2,396.36 25,325.01 2003 2,317.88 2,126.11 2,384.35 2,120.99 1,927.60 1,897.31 1,924.11 1,862.11 1,884.36 2,052.06 2,335.24 2,537.63 25,369.75 2004 2,548.56 2,250.05 2,382.98 2,070.73 1,908.87 1,804.20 1,890.61 1,789.51 1,937.04 2,134.48 2,343.60 2,575.84 25,636.46 2005 2,553.45 2,261.82 2,278.63 2,121.30 1,985.15 1,801.38 1,763.24 1,917.33 1,939.69 2,179.32 2,304.37 2,454.85 25,560.53 2006 2,472.10 2,229.88 2,525.44 2,168.17 2,057.66 1,827.20 1,999.30 1,962.42 1,895.53 2,116.15 2,364.57 2,653.95 26,272.36 2007 2,667.06 2,303.68 2,604.05 2,291.95 2,147.58 1,947.29 2,014.85 1,953.52 1,911.78 2,218.30 2,440.54 2,826.17 27,326.78 2008 2,818.54 2,555.32 2,610.78 2,422.91 2,233.71 2,063.59 2,081.92 2,088.97 2,018.55 2,367.35 2,432.76 2,942.00 28,636.39 2009 2,911.24 2,500.24 2,727.51 2,380.97 2,121.74 1,829.57 1,854.43 1,911.88 1,942.19 2,271.16 2,507.30 2,815.73 27,773.95 2010 2,637.61 2,270.42 2,573.38 2,308.19 2,100.10 1,988.63 1,920.43 1,823.13 1,797.99 2,194.72 2,434.87 2,754.84 26,804.30 2011 2,772.14 2,521.37 2,598.79 2,261.15 2,072.25 1,796.58 1,860.54 1,811.88 1,791.70 2,100.62 2463.82 2688.39 26,739.24 2012 2,897.13 2,494.01 2,627.27 2,205.02 2,149.75 1,879.79 1,864.13 N/A N/A N/A N/A N/A N/A Issued October 18, 2012 2

Chart 1 Chart 2 Issued October 18, 2012 3

2.2 Demand Load & Generation Output Assessment The electrical energy generated by the existing MAS DGS is intended to be reduced, in part or entirely, by clean or renewable electricity to be provided by a successful Respondent. As a base assumption, the MAS DGS will remain as standby units and may also operate as prime units to support black start and supplementary back-up for the N-1 criterion. The historical peak loads for January 2001 to July 2012 are summarized in Table 4 and graphically illustrated in Chart 3 and Chart 4. Note that the abnormally high January 2012 peak of 6219 kw was a rare, temporary load spike caused by unusually cold weather. This compares to more recent peak loads of approximately 4,500 kw to 5,200 kw. Chart 3 displays the data from Table 4 by year. For example, in 2003, the maximum monthly peak was 4,530 kw (black diamond) whereas the minimum monthly was 3,300 kw (range bar). Similarly, Chart 4 displays the data from Table 4 by month. For example, in September (month 9), the maximum peak for the 2001-2011 period was 3,725 kw (black diamond) whereas the minimum peak was 3,440 kw (range bar). Table 4: MAS DGS peak load [kw] Jan. 2001 July 2012 Year Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Min Ave Max 2001 4200 4400 4125 4000 3850 3480 3550 3210 3440 4000 4560 4640 3210 3954 4640 2002 4610 4350 4380 4160 3800 3500 3250 3300 3725 4100 4065 4340 3250 3965 4610 2003 4280 4085 4530 3900 3700 3300 3300 3310 3700 3811 4320 4500 3300 3894 4530 2004 4840 4400 4165 3900 3450 3300 3400 3115 3700 3820 4650 4884 3115 3968 4884 2005 4888 4315 4171 3900 3710 3398 3150 3411 3715 4038 4360 4335 3150 3949 4888 2006 4311 4287 4460 3878 3862 3350 3410 3500 3520 4082 5000 4660 3350 4026 5000 2007 4897 4800 4620 4261 3900 3499 3584 3511 3510 3900 4446 5090 3499 4168 5090 2008 4953 4745 5200 4132 4215 3870 4000 4110 3562 4200 4400 5274 3562 4388 5274 2009 5007 4875 4570 4350 3852 3452 3265 3416 3525 4190 4610 5190 3265 4191 5190 2010 4655 4251 4980 4320 3784 3696 3300 3140 3471 3885 4680 4629 3140 4065 4980 2011 5100 5260 5036 4130 3957 3269 3265 3170 3474 3725 4464 4771 3170 4135 5260 2012 6219 4553 4482 4140 3867 3400 3300 N/A N/A N/A N/A N/A 3300 4280 6219 Issued October 18, 2012 4

Chart 3 Chart 4 Issued October 18, 2012 5

2.3 Forecasted Demand The forecasted gross energy 2 for the fiscal years 3 F2013 to F2033 is tabulated in Table 5 below and graphically represented in Chart 5. There are three scenarios presented: probable or most likely scenario, low growth scenario and high growth scenario. The gross load includes both distribution losses and station service, which add approximately 5-8% to net or saleable energy volumes. Table 5: MAS forecast gross load growth Probable Scenario High Scenario Low Scenario Year-over- Year Change Year-over- Year Change Year-over- Year Change Fiscal Year [MWh] [MWh] [MWh] ACTUAL F2011 27,215-27,215 27,215 ACTUAL F2012 26,865-1.29% 26,865 n/a 26,865 n/a F2013 27,454 2.19% 29,181 n/a 25,727 n/a F2014 27,995 1.97% 29,741 1.92% 26,248 2.02% F2015 28,323 1.17% 30,080 1.14% 26,567 1.21% F2016 28,535 0.75% 30,298 0.72% 26,772 0.77% F2017 28,687 0.53% 30,455 0.52% 26,919 0.55% F2018 28,855 0.59% 30,628 0.57% 27,082 0.60% F2019 28,970 0.40% 30,748 0.39% 27,192 0.41% F2020 29,069 0.34% 30,851 0.33% 27,288 0.35% F2021 29,172 0.35% 30,957 0.34% 27,386 0.36% F2022 29,285 0.39% 31,075 0.38% 27,495 0.40% F2023 29,367 0.28% 31,160 0.27% 27,575 0.29% F2024 29,456 0.30% 31,250 0.29% 27,662 0.31% F2025 29,499 0.15% 31,293 0.14% 27,705 0.16% F2026 29,542 0.15% 31,336 0.14% 27,748 0.16% F2027 29,566 0.08% 31,358 0.07% 27,774 0.09% F2028 29,622 0.19% 31,414 0.18% 27,830 0.20% F2029 29,662 0.13% 31,454 0.13% 27,869 0.14% F2030 29,698 0.12% 31,489 0.11% 27,906 0.13% F2031 29,714 0.05% 31,502 0.04% 27,925 0.07% F2032 29,746 0.11% 31,532 0.10% 27,960 0.12% F2033 29,759 0.04% 31,544 0.04% 27,975 0.05% 2 Compiled from information prepared by BC Hydro s Load Forecast Group. 3 BC Hydro s fiscal year is from April 1 to March 31. For example, F2012 runs from April 1, 2011 to March 31, 2012. Issued October 18, 2012 6

Chart 5 2.4 Other Useful Charts Station load profiles for various time ranges are shown in Chart 6 through Chart 18. The charts are indicative only and are not intended to be exhaustive; rather, the charts are intended to assist the Respondent in establishing the load profile. Chart 6 through Chart 8 These charts display 15 min average net station output over two years 30-Sep-2010 to 29-Sep-2012. Note that the abnormally high January 2012 load spike was a rare, temporary event caused by unusually cold weather. Chart 6 and Chart 7 display the time-series 15-minute average data and the moving daily average. Chart 8 displays the two years of data in a percent exceedence chart. For example, approximately 70% of the time the load exceeded approximately 2.6 MW; the median load at 50% is about 2.9 MW and 90% of the time the load was between 1.8 MW (95%) and 4.0 MW (5%). Chart 9 through Chart 12 These charts display 15-minute average net station output examples for four weeks in 2011 during different seasons showing how the loads change over the day and week. Chart 15 through Chart 18 These charts display the gross station generation output for four specific months in 2011 showing the range of values at the specific time of day. For example, in Chart 15 during the month of January 2011, the range of loads observed at 10:00 a.m. range from about 3.6 MW to 5.1 MW. Issued October 18, 2012 7

Chart 6 Chart 7 Issued October 18, 2012 8

Chart 8 Chart 9 Issued October 18, 2012 9

Chart 10 Chart 11 Issued October 18, 2012 10

Chart 12 Chart 13 Issued October 18, 2012 11

Chart 14 Chart 15 Issued October 18, 2012 12

Chart 16 Chart 17 Issued October 18, 2012 13

Chart 18 3. SYSTEMREQUIREMENTS 3.1 Projects Interconnected to the Distribution System For the purposes of this RFEOI, Respondents do not have to submit an interconnection study. Respondents should be aware that should a commercial process be undertaken, their projects would be required to comply with the appropriate interconnection requirements for a distribution-connected project. BC Hydro s technical interconnection requirements, including criteria for frequency and voltage control and harmonic content, are outlined in a document entitled BC Hydro 35kV and Below Interconnection Requirements for Power Generators, February 2010, which may be found at www.bchydro.com (go to: home page > planning and regulatory > acquiring power > generator interconnections > distribution interconnection requirements). These requirements may be updated or replaced from time to time. Respondents would be required to ensure that their project and its output maintain the electrical quality and/or the reliability of BC Hydro s customer service. BC Hydro will control the operation of the tie line and the amount of delivery as necessary for security and reliability. In a Non Integrated Area (NIA), the reliability of the supply is of particular concern. Failure of the Respondent s supply could cause an interruption in customer service and restoration delays while communication is initiated between BC Hydro and the Respondent. Interconnection studies are conducted to ensure that interconnection is accomplished in a reliable and safe manner. The preferred interconnection point would be the Masset diesel generating station substation. However, other connection options proposed by the Respondent may be considered by BC Hydro. Issued October 18, 2012 14

BC Hydro s NIA group has good experience with integration of mini-hydro generation and diesel generation. Mini-hydro is generally considered a firm, non-intermittent source of power with load following capabilities. Any other types of intermittent, non-firm energy profiles have not been proven on NIA diesel-based micro grids and significant technical due diligence is required to prove the level of and rate of change in power supply (MWs) that could be accommodated on the North Grid, without adversely affecting power quality and reliability. The following two sections provide some guidance on the integration of wind and bioenergy projects with diesel generation. 3.2 Wind Energy Wind power interconnection requirements have been established by BC Hydro and may be applicable to distribution-connected projects; however, it will be the responsibility of the Respondent to use best industry practice in the design of their project. Information with respect to wind power interconnection requirements is available on BC Hydro s website. However, it should be noted that power quality and stability of small diesel-based microgrids is much more fragile and sensitive to load and supply power swings than the integrated system and therefore the BC Hydro power interconnection requirements for wind projects do not fully apply for this RFEOI. Wind proposals may need significant system modelling and impact studies to prove that the system can maintain power quality and stability standards when the project is integrated with the diesel-based North Grid system. Table 6 below is a general guide that BC Hydro uses for the three wind penetration classes in an integrated wind-diesel system. Table 6: Wind penetration classes Penetration Operating characteristics Class Average 4 Peak 5 Low < 20% < 50% Diesel runs full time Wind power reduces net load on diesel All wind energy goes to primary load No supervisory control system Medium 20 50% 50 100% Diesel runs full time At high wind power levels, dump loads dispatched to ensure sufficient diesel loading Alternatively, wind turbines are curtailed during high winds and low loads Requires relatively simple control system High 50 150% 100-400% Diesels may be shut down during high wind availability Auxiliary components required to regulate voltage and frequency Requires sophisticated control system BC Hydro recently engaged Powertech Labs to develop a dynamic simulation framework for microgrids with the Haida Gwaii North Grid as a case study. This study concludes that the average penetration level can be as high as 26% without compromising the level of system stability that currently exists. This corresponds to a nameplate wind power capacity of approximately 2.0 MW and annual wind energy production of 7,715 MWh. The primary electrical load has an approximate peak of 5 MW and expected annual energy consumption is approximately 27,000 MWh. Beyond this wind penetration level (26% average), additional systems would be required including supervisory controllers, energy storage devices, 4 Average Penetration (over a year) = Wind Energy Produced (MWh) / Primary Energy Demand (MWh) 5 Peak Penetration = Wind Power Output (MW) / Primary Electrical Load (MW) Issued October 18, 2012 15

and dump loads. Further modelling would be required to determine the optimum mix (wind penetration level, energy storage level, dump loads, load curtailment, etc.) This study would be done as part of the interconnection study and paid for by the Respondent. 3.3 Bioenergy Option 1 Load following A load following bioenergy system could potentially support the full load of the community all year round with the existing diesel generating station in standby mode and ready to generate electricity as necessitated up to the full community load requirements. Option 2 Non-load following Year round base load A non-load following bioenergy system could be sized to provide constant power all year round with the existing diesel generating station supporting the deficit in a load following mode. In this case, the bioenergy system can be sized to equal the minimum daily summer load minus 70% of the prime rating of the smallest diesel generator. This margin is required to ensure that the smallest diesel generator can provide load following at the low end without being under-loaded. A rough calculation therefore suggests that a 1 MW bioenergy system would be optimal (see Chart 8, Chart 15). Option 3 Non-load following Seasonal base load A non-load following bioenergy system can be designed to provide three different levels of base power one for winter, one for spring/fall and one for summer. In addition, the system has to work with the existing diesel generating station to accommodate daily load fluctuations above and below the seasonal base power level. This may require that the bioenergy system to change output over a day. A rough estimation would point to a bioenergy system with average seasonal outputs of 1 MW, 2 MW and 2.5 MW for summer, spring/fall and winter respectively (see Chart 9 to Chart 14). 3.4 Revenue Metering The metering for a clean or renewable electricity project shall be in accordance with BC Hydro requirements for remotely-read load profile revenue metering. Details concerning such requirements are available upon request. This will be assessed and handled in the impact/design study stage and all metering costs will be paid by the Respondent. 3.5 Interconnection Request Process In general, the interconnection process includes the following steps: generator interconnection application document submission, preliminary study to determine the technical and economic feasibility of the interconnection, impact design study to identify the project interconnection requirements and sign interconnection agreement, and implementation of the connection, including construction and final commissioning of the connection to BC Hydro s distribution network. 3.6 Responsibility for Costs The costs of revenue meters, interconnection studies, licensing, approvals and the physical interconnection up to the point of interconnection including any BC Hydro capital costs to extend or upgrade the distribution system (including revenue metering) are the responsibility of the Respondent. Issued October 18, 2012 16