somass basin hydro assessment - british...

Somass Basin Hydro Assessment

Living Rivers Trust Fund and BC Conservation Foundation

Final Report 31 January 2012

Living Rivers Somass Basin Hydro Assessment i

DISCLAIMER This document is for the private information and benefit of the client for whom it was prepared and for the particular purpose for which it was developed. The contents of this document are not to be relied upon or used, in whole or in part, by or for the benefit of others without specific written authorization from Northwest Hydraulic Consultants Ltd. (NHC).

This document represents Northwest Hydraulic Consultants professional judgment based on the information available at the time of its completion, and appropriate for the scope of work engaged. Services performed in developing the materials provided in this report have been done in a manner consistent with the proficiency and skill of members in professional practice as an engineer or geoscientist practicing in similar conditions and environments.

This report, all text, pictures, data, figures and drawings include herein, are copyright of Northwest Hydraulic Consultants Ltd. The Client is permitted to reproduce materials for archiving purposes and distribution to third parties only as required to conduct business related to the parties. Any other use of these materials without the written permission of NHC is prohibited.

CITATION

NHC and Compass Resource Management. 31 January 2012. Somass Basin Hydro Assessment. Prepared for Living Rivers Trust Fund.

Copyright © 2012

ACKNOWLEDGEMENTS

The authors wish to acknowledge the assistance of Al Lill and Craig Wightman in this study.

CERTIFICATION Report prepared by:

Ned Atkins, PEng

Will Cleveland, MSc

Report reviewed by:

Barry Chilibeck, MASc, PEng, APEGBC #17430

Dan Ohlson, MSc, PEng, MCIP

Accepted final report to be sealed and retained on file.

Living Rivers ii Somass Basin Hydro Assessment

EXECUTIVE SUMMARY The Somass Basin Watershed Management Plan Status Overview Report identifies a broad interest in assessing the potential for the development of green hydro renewable energy sources. This report presents an assessment of two potential hydroelectric projects at Great Central Lake (GCL) and Elsie Lake, focussing primarily on engineering and economic viability, and regulatory considerations.

Options for generation of hydroelectricity at Great Central Lake are limited by the low head available at the dam and location to construct a project. Based on the engineering constraints, a single unit consisting of a variable pitch, Ecobulb axial flow turbine manufactured by Andritz was used as the technical design basis. The variable capacity provides high efficiency over a wide range of flows, as well as low fish mortality – largely associated with blade and contact strike within the unit.

An operational model was developed to estimate daily power generation and project optimization techniques were used to determine a notional plant capacity for the detailed financial proforma model. Preliminary quantity take-offs and scaling were used to estimate construction and equipment costs to a Class D level. Further optimization of the plant size would likely take place during detailed design.

Capital costs associated with construction of a project are relatively high ranging from $5.8M to $3.8M per MW installed. Conceptual costs to provide fish protection with permanent screens, additional fish passage with fishways and fish barrier at the tailrace add to the already high capital costs. This assessment also considered scenarios where no fish screens were installed at the intake, but plant operations are curtailed to protect downstream smolt migration.

The optimum plant size identified was approximately 4.2 MW at a flow of 70 m3/s, and utilizing the sixteen year historical hydrological data string, the proposed plant produces an average of 21.6 GWh per year (±3.4 GWh = 1-STDEV) not including any mandated shutdown period. The estimated construction cost was $36.1 million with fish screens installed, or $23 million with fish screens excluded, plus approximately $1 million in net additional costs for interest during construction and reserve account funding. Excluding fish screen costs and shutting down during the smolt migration period (assumed to be all of April) was identified as the most attractive approach given the high cost of fish screens.

A detailed financial proforma of the operation of potential hydroelectric plant at Great Central Lake was undertaken, developing rates of return and cash flows. Variables and outputs in the financial analyses included:

- Capital costs and assumptions

- Financing terms

- Electricity revenue

- Capital structure and equity IRR

Sensitivities to several financial variables were examined. Using the optimized design described above, assuming no fish screen installation and a shutdown for the month of April, the total project budget would be $24.1 million. With the highest acceptable leverage, the project would require an $18.8 million loan and a $5.3 million equity investment. The equity provider would earn a return of 7.2%, which is considered below the target return range of 10% - 15% for projects of this type.

Living Rivers Somass Basin Hydro Assessment iii

A similar proforma was developed for the Elsie Lake Dam Hollow Cone Valve instream flow release opportunity, based on the same financing and revenue assumptions. This project would generate 3,000 MWh per year with total costs of $5.2 million. The equity provider would earn a return of 5.8%, which is considerably below the target return range.

Living Rivers iv Somass Basin Hydro Assessment

TABLE OF CONTENTS DISCLAIMER ..................................................................................................................................... I

CITATION ........................................................................................................................................ I

ACKNOWLEDGEMENTS ....................................................................................................................... I

CERTIFICATION ................................................................................................................................. I

EXECUTIVE SUMMARY ....................................................................................................................... II

1 INTRODUCTION ........................................................................................................................ 1

2 OVERVIEW OF HYDROPOWER DEVELOPMENTS ................................................................................. 2

2.1 Operating Projects .................................................................................................................. 2

2.2 Projects under Development .................................................................................................. 2

2.3 Other Potential Projects.......................................................................................................... 2

3 ASSESSMENT OF POTENTIAL HYDROPOWER DEVELOPMENT AT GREAT CENTRAL LAKE ................................ 3

3.1 Fish Protection and Passage ................................................................................................... 3

3.2 Conceptual Design .................................................................................................................. 5

3.3 Proposed Operational Scenario ............................................................................................ 11

3.4 Regulatory Considerations .................................................................................................... 11

4 POWER GENERATION ESTIMATES ................................................................................................ 14

4.1 Hydrology .............................................................................................................................. 14

4.2 Estimation of Mean Annual Energy Generation ................................................................... 14

5 OPTIMIZATION AND FINANCIAL ANALYSES .................................................................................... 15

5.1 Plant Optimization ................................................................................................................ 15

5.2 Electricity Sales Revenue ...................................................................................................... 15

5.3 Estimation of Capital Cost ..................................................................................................... 16

5.4 Operating Costs ..................................................................................................................... 16

5.5 Capital Structure, Financing Costs and Reserve Accounts .................................................... 16

6 SUMMARY OF RESULTS ............................................................................................................ 18

7 SENSITIVITY ANALYSIS .............................................................................................................. 21

8 ELSIE LAKE ENERGY RECOVERY PROJECT ....................................................................................... 22

9 SUMMARY ............................................................................................................................ 24

10 REFERENCES .......................................................................................................................... 25

10.1 Personal Communication ...................................................................................................... 25

APPENDIX A – GCL SAMPLE CASH FLOWS, JULY 2014 TO JUNE 2015 ........................................................ 26

Living Rivers Somass Basin Hydro Assessment v

APPENDIX B – GCL SAMPLE CASH FLOWS, 2017 ................................................................................... 29

APPENDIX C – GCL CAPITAL COSTS .................................................................................................... 31

APPENDIX D – ELSIE LAKE SAMPLE CASH FLOWS, JULY 2014 TO JUNE 2015 ................................................ 34

APPENDIX E – ELSIE LAKE SAMPLE CASH FLOWS, 2017 ........................................................................... 36

LIST OF TABLES Table 1 Operating hydro projects in the Somass River Basin. ......................................................... 2

Table 2 Waterpower Projects Applicable Legislation. ................................................................... 11

Table 3 Plant Capacity Optimization Summary. ............................................................................ 15

Table 4 BC Hydro Price Adjustment Summary for SOP. ................................................................ 15

Table 5 Operating Costs................................................................................................................. 16

Table 6 Total Project Costs – Fish Screen Configuration ............................................................... 18

Table 7 Capital Structure – Fish Screen Configuration .................................................................. 18

Table 8 Average Monthly Energy Generation ............................................................................... 19

Table 9 Total Project Costs – No Fish Screen................................................................................. 19

Table 10 Capital Structure – No Fish Screen ................................................................................... 20

Table 11 Summary of Sensitivity Analysis ....................................................................................... 21

LIST OF FIGURES Figure 1 Hydrokinetic Turbine Units on the Yukon River. ................................................................ 6

Figure 2 Screw Turbine Units. ........................................................................................................... 7

Figure 3 Ecobulb and VLH Turbine Units. ......................................................................................... 8

Figure 4 Typical Eco bulb layout (Source: Andritz hydro). ................................................................ 9

Figure 5 Proposed Powerhouse Location. ...................................................................................... 10

Figure 6 Typical Clean Energy Project Development Sequence (Province of BC, 2011)................. 13

Living Rivers Somass Basin Hydro Assessment 1

1 INTRODUCTION The Somass Basin Watershed Management Plan Status Overview Report identifies a broad interest in assessing the potential for the development of green hydro renewable energy sources. This report presents an assessment of two opportunities at Great Central Lake (GCL) and Elsie Lake, focussing primarily on economic viability and regulatory considerations.

In undertaking this study, Northwest Hydraulic Consultants (NHC) and Compass Resource Management Ltd. (Compass) reviewed previous studies undertaken, built upon existing technical and environmental studies, and collaborated with key technical experts in government and industry.

The scope of the assessment included four tasks:

1. Review of existing and potential renewable hydro development sites in the Somass Basin.

2. Preliminary assessment of key issues related to future development (e.g., transmission, flood management, fish passage, aquatic habitat loss).

3. Development of conceptual designs and optimization of plant design size based on basic revenue and capital cost estimates.

4. Development of a proforma financial analysis for the opportunities at GCL utilizing updated development, environmental mitigation costs and current energy pricing.

Living Rivers 2 Somass Basin Hydro Assessment

2 OVERVIEW OF HYDROPOWER DEVELOPMENTS

2.1 OPERATING PROJECTS There are several operating hydro projects within the Somass River basin. Ash River is the largest, operated by BC Hydro on the Ash River with storage on Elsie Lake. It is also the most significant in terms of effects on Great Central Lake, as it diverts water from Elsie Lake into Great Central Lake itself. Other projects in the basin have been developed under previous calls from BC Hydro for power, and are listed in Table 1.

TABLE 1 OPERATING HYDRO PROJECTS IN THE SOMASS RIVER BASIN.

2.2 PROJECTS UNDER DEVELOPMENT There are currently no hydropower projects under active development in the Somass River basin. There are several projects outside the basin currently under development or construction.

2.3 OTHER POTENTIAL PROJECTS An overview assessment of opportunities within the Somass basin was undertaken as a background to this study. Drinkwater Creek was identified in an earlier hydro assessment study conducted in 2000, however no other tributary systems were noted. For the purposes of this work, we also reviewed the potential for energy recovery on the outlet of Elsie Lake on the Ash River, tributary to the Stamp River. Currently, instream flows are discharged from Elsie Lake via a hollow cone valve at the BC Hydro Ash River Project.

Capacity Flow Energy Type(MW) (m3/s) (GWh) or Storage (Mm3)

Summit Power Corp. Doran Lake/Porter Creek 5.3 1.1 25 2.343

Klitsa Creek Hydro Inc. Klitsa Creek 4 1 15 ROR

South Sutton Creek Hydro Inc. South Sutton Creek 5 2 16 ROR

BC Hydro and Power Authority Elsie Lake/Ash River 25.2 13.9 193 76.5

Project Stream Name


3 ASSESSMENT OF POTENTIAL HYDROPOWER DEVELOPMENT AT

GREAT CENTRAL LAKE

3.1 FISH PROTECTION AND PASSAGE The primary environmental issue related to hydropower generation at Great Central Lake dam is fish protection and passage. Currently, a vertical slot fishway provides upstream fish passage for returning adult salmon and resident fish. Based on fish movement studies, the predominant mode of smolt passage downstream will be over the dam crest, following bulk flows and hydraulics. The efficiency of the existing fishway and potential mortality of passage over the stoplog crest is unknown.

The largest stocks using the fishway are sockeye salmon, with an average escapement of 190,000 fish producing 8,770,000 smolts (Hyatt 2011). There is also incidental migration production of steelhead, coho and chinook salmon above the dam, and all these fish move downstream in spring to the Somass Estuary and Barkley Sound. The fishway likely supports the seasonal movement of resident trout from the lake into the Stamp River. A hydroelectric project at Great Central Lake Dam will require:

1. Maintenance or expansion of upstream fish passage above the project;

2. Protection of fish from entrainment into the project intake and turbines; and

3. Minimization of mortality of fish entrained into the project turbine.

3.1.1 UPSTREAM FISH PASSAGE

Currently a 19 baffle vertical slot fishway provides upstream passage over the dam. The fishway is located on the right side of the structure and operates independently of the dam operations. According to the original design drawings, a pool at the base for the fishway entrance and dam was blasted into the river bed. Concrete sills were installed on the rock ledge immediately downstream of the dam above this pool, to produce a barrier. No guidance flows are provided from the dam, and fish seek out the fishway opportunistically.

With a potential hydro project constructed on the left bank, an additional fishway may be required at or near the project to provide passage for fish attracted to the tailrace. A tailrace barrier system may also be required to exclude adults from the turbines and guide fish to the upstream fishway system. The costs of an additional fishway and tailrace barrier should be included with the conceptual costs for the project.

3.1.2 DOWNSTREAM FISH PROTECTION

At the Great Central Lake Dam, a downstream moving fish has simple alternatives: be excluded from the intake, pass through the turbine or pass over the dam crest.

Entrainment reduction of downstream migrating fish at hydropower projects typically consists of some type of physical barrier used to exclude fish from entering the turbine intakes. Common examples are vertical bar racks, fixed and moving screens and louvers. The barriers are generally combined with some type of bypass system to safely deliver fish downstream past the facility.


A review of the literature revealed that bar racks and fish screens have been installed in many hydroelectric projects for mitigating the entrainment of downstream migrating fish. The racks have generally been prescribed and installed to limit entrainment of larger sizes or adult fish with bar spacing between 25 and 50 mm. This mitigation would be required for larger resident trout and steelhead kelts.

It was also found that the vast majority of fish entrained at these plants are less than 200 mm in length. Although narrower racks would physically exclude smaller fish, often maintenance and debris loading – especially on fixed racks – precludes their continuous use. In some cases, debris accumulations and rack cleaning procedures can injure fish or lead to their impingement or entrainment. Many applications use temporary overlays to achieve the desired spacing during peak migration periods only. Again these overlays are sized to exclude a certain size of fish.

At run-of-river facilities, bar racks are practical for ensuring debris and larger fish are kept out of the intake, but they would not be effective for the small fish lengths typical of the migrating smolts and juvenile fish species in Great Central Lake and the Stamp River.

Both stationary and moving screens have been used to provide physical exclusion of fish – typically small juvenile fish – from intakes. In the case of small fish, fry and other organisms that do not have strong swimming ability, entrainment reduction requires very low approach velocities to the screen face, significant bypass flows to ensure the small fish are removed from the screen face and bypass structures that safely move the fish downstream of the intake to a safe location.

The screen openings are small, requiring large intake surface areas to provide diverted flow volumes. The large screen areas are subject to differential head losses, significant hydraulic forces and intensive maintenance. While static screens with manual cleaning can be used on relatively small flows, larger diversion have typically used inclined screens with mechanical cleaning systems, vertical travelling screens or large drum screening facilities to be effective. Fish handling is an important criteria to minimize scale loss and reduce delay.

If fish entrainment protection is provided at a hydro project at Great Central Lake Dam, there are many potential options. Given the project constraints, barrier nets and louvers, inclined screens or high speed screens could all be potentially viable. For the purposes of this study, we assumed that the fish protection must provide positive physical exclusion, effective diversion and safe bypass for all fish species and sizes – similar to the Eicher Screen at the BC Hydro Puntledge River Generating Station. Non-factored costs for screening facilities at similar sized projects were obtained from the literature, and an estimate of $100,000 to $120,000 per m3/s diverted was used to estimate “all-in” costs.

3.1.3 TURBINE PASSAGE AND SPILLING

Given the low head of the facility and likely use of an eco-friendly turbine technology, there is a potential to not to install a screen system and:

1. Pass all downstream fish through a fish friendly, low mortality turbine units; or

2. Shut down generation during peak downstream smolt movements, and preferentially spill over the dam.

Fish passing through turbines can be damaged or killed by rapid increases in pressure, cavitation, strike, grinding, turbulence, and shear stress (Ćada et al. 2007). In addition, disorientation caused by the high turbulence increases susceptibility to predation downstream in the tailrace and river.


The likelihood and severity of fish injury and mortality varies greatly depending on project configuration, flows, operating head and type of turbine. Mortality rates also vary by fish species, size, and life stage, but are difficult to predict (Ćada et al. 2007). Alden (2001) conducted a literature review of fish mortality related to passage through low head bulb turbines, similar to what would be installed at Great Central Lake. For fish lengths < 100 mm, turbine survival ranged from 85% to 98% (i.e., mortality of 2% to 15%).

Previous studies have shown an increase in turbine mortality rates with fish size, and that survival was generally higher for smaller fish. These values and conclusions are similar to those reported by Therrien and Boureois (2000) and Franke et al. (1997). New turbines designs now under physical model testing exhibit survivals of 97% to 100% based on empirical studies with 40,000 fish of varying species and sizes (Perkins 2011).

Methods for reducing mortality and injury due to the turbine are typically related to turbine design elements that are specific to the type of unit selected for optimizing power production with the head and flows at the facility. These elements include: elimination of wicket gates, minimizing the number of blades or the amount of blade leading edge, maximizing the open space between blades and other structures, using blunt leading edges on the turbine blade, minimizing runner speed, directing fish toward the runner hub and minimizing gaps between fixed and moving parts (USDOE 1997). Running the turbines near peak efficiency also helps increase turbine survival due to decreases in turbulence, pressure changes and cavitation (Ćada 2001). Many of these attributes are incorporated in variable pitch, axial flow turbines.

A detailed assessment of the implications of a screened or non-screened fish-friendly turbine have not been undertaken. We have not assessed the utility of barrier nets, louvers or other partial barriers that may provide a high level of protection but not 100% physical exclusion. Our assumption is that the facility is either effectively screened or shut down during the downstream smolt migration period – assumed to be April annually. Regulatory approval and certainty may be an overriding factor in the selection of a preferred option.

In either scenario, the screen may only need to be sized for smolts (parr) resulting in a larger screen opening with the potential entrainment of fish less than 25 to 30 mm in length at the very low mortality rates associated with this type of turbine.

3.2 CONCEPTUAL DESIGN There are several low head or very low head (VLH) turbine systems with potential application at GCL Dam. These include both hydrokinetic type turbines that utilize blades of fins in flowing water; open reaction-type systems like Archimedes screws, and closed propeller-type reaction turbines.

Figure 1 is a picture of a hydrokinetic turbine tested on the Yukon River, AK provided as an example of the technology. Typically, these turbines are either deployed as a floating or anchored system to harness flowing riverine or tidally-driven water currents. Hydrokinetic turbines require adequate depth of flow and relatively high velocities to generate power, and their application is not well suited to either the dam site or the river channel upstream. This technology was not considered further in this assessment.


FIGURE 1 HYDROKINETIC TURBINE UNITS ON THE YUKON RIVER.

Archimedes screw turbines are a relatively recent development, which utilize the robust characteristics of the screw pump system. Figure 2 is a photo of a larger turbine system, which typically utilize heads less than 10 m and flows less than 6 m3/s. Maximum output is 200 KW per unit and averages around 50 KW. These units have very robust debris handling and excellent fish protection characteristics. The generator and control gear is located at the top of the unit, and they are readily retrofitted into existing drainage and weir systems.


FIGURE 2 SCREW TURBINE UNITS.

There are several LH/VLH turbines that utilize a bladed propeller–type turbine in either a bulb or Kaplan type configuration. Two units reviewed included the VLH turbine developed by MJ2 technologies and the Ecobulb turbine developed by Andritz. These turbines are reaction types that require the unit to be fully submerged. In both the VLH and Eco Bulb unit, the turbine is directly connected to the generator thus avoiding the need for a gearbox. Both turbines are similar, as they are multi-bladed Kaplan designs that have been optimized for low operating head and minimization of fish injury and mortality.

There are several other low and very low head, small and micro hydro designs that can be adapted to a wide range of site conditions. The designs reviewed here are intended to comprise the spectrum of designs that have likely application at Great Central Lake Dam, and is not inclusive to all designs or applications.


FIGURE 3 ECOBULB AND VLH TURBINE UNITS.

3.2.1 TURBINE SELECTION

For a low head high-flow application, flexible efficient operation is required. Since this is a project which will effectively be operated similar to a run-of-river hydro facility, one of the requirements will be to perform at high efficiency over a range of flows. This can be achieved by either having several turbines of smaller capacity or having one turbine with the adjustability to maintain a high efficiency.

Previous assessment conducted by Sigma Engineering (1999) opted for a fixed pitch propeller-type turbine that required multiple units to provide both capacity and efficiency over the range of operating flows (10 to +60 m3/s). The VLH turbine is at the upper end of its operating head and would require up to 4 units passing up to 20 m3/s or 5 units passing up to 15 m3/s for a viable configuration. This would also be the case for a screw turbine with even more units required. The Ecobulb can utilize a single large diameter unit with variable pitch blades to operate efficiently over the expected range of flows.

Listed below are some of the other factors regarding turbine selection at Great Central Lake Dam:

1. Since this is a relatively low capacity facility (2 to 5 MW) it has been considered more economically viable to select one versatile turbine with minimal civil works as opposed to several smaller units.

2. Installation on the existing dam was not an option due to structural and foundation issues and the costs of reconstruction, and loss of operational capacity of the dam during construction.

3. The turbine units would require a high degree of efficiency and reliability due to the low head and cost sensitivity to energy production.

4. Minimizing civil works and overall project size reduces construction costs. A more compact project site would enable a flexible layout providing better approach and tailrace hydraulics.

5. Great Central Lake levels vary considerably during the season and rise rapidly during large floods. The turbine and configuration must be able to shut-down quickly and accommodate varying headwater elevations. The unit must either be flood-proofed or allow overtopping


6. The unit should be commercial availability, with design and support services, and a proven operational history.

Structural limitations of the existing structure and the design standards and reliability required for new works limit the use of the existing dam or pier in the construction of the hydro plant. The requirements to maintain hydraulic control and follow dam safety regulations and orders make utilization of the existing weir crest not feasible

We excluded the VLH at GCL for several valid technical reasons primarily that the design head is greater than the rated maximum design capacity, and multiple units (8 to 10) would be required to provide similar power generation. That said, the VLH technology is highly suited for very low head applications, and has excellent fish protection characteristics.

Of the available turbines, a compact Ecobulb has been selected for the design basis, which is a propriety design of Andritz Hydro. For this application a 100 RPM double regulated unit would be required. Although a detailed optimization analysis for turbine selection has not been carried out it is believed that this turbine will provide the best efficiency for the capital cost including installation and all civil works. This turbine has also been selected since it is said to be “fish friendly”, as it provides a low incidence of injury or mortality for fish passage through to turbine.

Should this project proceed to detailed design, we recommended that a turbine and generator supplier be engaged to provide guaranteed efficiency curves and quote for a range of turbine configurations in order to be able to verify the turbine selection.

3.2.2 SITING

Figure 4 shows a low head installation using an Ecobulb turbine. It is not scaled to the size of facility intended at Great Central Lake Dam, but provides a general arrangement. Figure 5 provides a general location of the powerhouse relative to the existing dam.

FIGURE 4 TYPICAL ECO BULB LAYOUT (SOURCE: ANDRITZ HYDRO).


The low head available at the site and large runner diameter require additional rock excavation to ensure sufficient submergence to avoid cavitation and vortexing. This basic physical constraint excludes the right abutment as a potential location for the power plant. The left abutment of the dam provides suitable access and the space to enable the coffering of the intake location for construction.

Figure 5 provides a general location of the propose powerhouse at Great Central Lake. The plant would be constructed on the left abutment area adjacent to the existing dam. This location provides access and ability to isolate the work site without impeding operation and flows at the dam. Earthen cofferdams would isolate the upstream area. The power house is approximately 15 m wide, 15 m long and 10-15 m deep lying in a canal up to 75 m long. The power canal is constructed through overburden into existing bed rock. The deep cut is required to fully submerge the 4.2 m diameter turbine under all flow conditions.

The project layout will depend on the decisions made regarding fish passage and protection. As stated earlier, the design review and financial analyse examines the implications of both scenarios: full fish screening and no screens with fish friendly turbines and partial shut-down. If a full fish screen is required then the intake structure will be considerably different to a simple trashrack for debris only. A static, high or low speed screen will require a forebay structure and metalwork, debris handling and fish handling works and bypass flows. It will be significantly larger and more costly than a simple bar trashrack intake.

Structural allowances have not been made for the notional coldwater supply system as detailed in NHC (2010). However, control works for this system could be provided in the additional fishway constructed adjacent to the new powerhouse.

FIGURE 5 PROPOSED POWERHOUSE LOCATION.


3.2.3 PROPOSED OPERATIONAL SCENARIO

The plant will operate based on a combination of level sensor gauges measuring both headwater and tailwater levels. The powerhouse PLC will be set a target lake elevation which it will try to maintain by adjusting the flow through the turbine. During a flood, the plant may be shut down to avoid damage due to the entrainment of debris.

We have assumed that the minimum spin flow is within the capacity of the turbine, and all flows would preferentially discharge through the powerhouse to maximize energy production. As stated earlier, efficiencies at these lower flows are assumed and more detailed data is required to refine energy estimates.

The operation of the plant was assumed to be independent of the dam, even though lake storage and elevations sustained by adding or removing stop logs or operating the sluice gate could affect power production. We have assumed no additional infrastructure is constructed with the powerhouse and intake, other than the works required for fish passage and protection. As detailed in the financial proforma, a sensitivity analysis was included to reflect additional capital funding to repair the existing dam, assuming it requires replacement before the hydro plant.

3.3 REGULATORY CONSIDERATIONS

Proponents of clean energy projects in BC must meet technical, commercial, and permitting requirements to develop a project as described in Clean Energy Production in BC: An Inter-agency Guidebook for Proponents (Province of BC, 2011). As a general overall guide to proponents, the guidebook provides a thorough description of the interplay between these requirements as summarized in Figure 6.

In terms of the permitting aspects and overall regulatory requirements, a typical project must undertake a series of steps to obtain regulatory approvals, during each of the design, construction and commissioning/operating phases. Key legislation which most waterpower projects must comply, provincially and federally, include:

TABLE 2 WATERPOWER PROJECTS APPLICABLE LEGISLATION.

Provincial Legislation: Federal Legislation:

• Land Act • Clean Energy Act • Water Act • Forest Act • Forest and Range Practices Act • Highway Act • Environmental Assessment Act • Water Protection Act • Wildlife Act • Fish Protection Act • Parks Act • Heritage Conservation Act

• Fisheries Act • Navigable Waters Protection Act • Canadian Environmental Assessment Act • Species at Risk Act • National Energy Board Act • Migratory Birds Convention Act

From a Provincial perspective, significant regulatory requirements for a hydropower development project at GCL would include:


1. Land Act tenures for all investigation and occupation requirements associated with siting the generating station; and

2. A water license (or amendment to the existing license) under the Water Act, and confirmation that all Dam Safety regulations, and downstream instream flow management requirements are met.

From a Federal perspective, the most significant regulatory requirements are expected to result from the Fisheries Act. Fish passage considerations (Section 20) – including any changes that reduce depths, increase velocities, change migration cues, or present physical barriers to fish movement – and the potential for fish entrainment and mortality (Section 32) through the turbines are expected to be key considerations in the overall project design as described above. It is also very likely that the project development will result in the harmful alteration, disruption or destruction (HADD) of fish habitat (Section 35), which will require the design and implementation of suitable mitigation or compensation measures in order to acquire authorization.

These authorizations will trigger the need to conduct a screening and environmental assessment under the Canadian Environmental Assessment Act (CEAA) and thus the preparation of a complete Environmental Impact Statement (EIS) report. Any detailed design requirements for mitigation (e.g., fish protection and passage facilities, fish screens, etc.) will require full proofing via modelling and detailed assessment in order to acquire the necessary authorizations. These regulatory requirements have significant implications for the technical design aspects as discussed above, and the financial requirements as discussed below.

In a watershed with such high fisheries values, it should be expected that acquiring the necessary Fisheries Act or CEAA approvals will add significantly to the overall project timeline.


FIGURE 6 TYPICAL CLEAN ENERGY PROJECT DEVELOPMENT SEQUENCE (PROVINCE OF BC, 2011).


4 POWER GENERATION ESTIMATES

4.1 HYDROLOGY Sixteen (16) years of lake elevation and outflow records were available from which to build to hydrological time series for available turbine flow. Daily inflow rate was calculated by back calculating from outflow and lake elevation records, then, this inflow was routed through the lake to calculate a inflow / outflow hydrograph.

From the outflow hydrograph, a portion or all of this flow was utilized for power generation. As expected, the large variability of the inflow hydrograph was greatly attenuated by the large lake, and hence the outflow hydrograph appears to be much flatter. The effect of this attenuation on a hydro project is beneficial since it is no longer necessary to capture the peak flows during the spring freshet since the flows are steadier. The result of this is that the design flow can be lowered thus reducing the capital cost because without compromising the capacity factor of the power plant.

4.2 ESTIMATION OF MEAN ANNUAL ENERGY GENERATION

Mean annual energy generation was calculated using an energy model in Microsoft Excel®. Sixteen (16) years of data was available from which a string file of “available turbine flow” was generated. The available turbine flow, lake elevation and corresponding tailwater elevations were then used in conjunction with electro-mechanical and hydraulic efficiencies to calculate daily energy generation. Transmission losses (0.2%) were accounted for in the model, as well as maintenance (1%) and unscheduled outages (1%).

The mean annual energy generation was used to calculate projected mean annual revenue based on peak, super peak and off peak prices offered by the BC Hydro Standing Offer Program for projects under 15 MW. The mean annual energy generation and the estimated capital cost were carried forward into the financial analysis.


5 OPTIMIZATION AND FINANCIAL ANALYSES

5.1 PLANT OPTIMIZATION The design flow and turbine capacity for the proposed development was selected based on an optimization of estimated monthly energy generation (i.e. projected energy sales revenue) and costs (capital costs and operational costs). The optimization study investigated design flows from 10 m3/s to 120 m3/s, and for each option a capital cost and a mean annual energy production were estimated. These parameters were then input into the economic model to select the project which offers the maximum IRR. Table 3 Table 4below show a summary of the projects considered.

TABLE 3 PLANT CAPACITY OPTIMIZATION SUMMARY.

5.2 ELECTRICITY SALES REVENUE Electricity sales revenues are based on BC Hydro’s Standing Offer Program (SOP). The SOP sets a fixed price which BC Hydro is willing to pay for electricity generated by projects under 15 MW. This fixed price is based on a project’s location, and the year in which the Electricity Purchase Agreement (EPA) is signed. For projects located on Vancouver Island with an EPA signed in 2012, the base price paid by BC Hydro is projected to be $106.71 per MWh, assuming 2% inflation in 2012. This price would escalate at 50% of inflation for every year thereafter.

This base price is adjusted further based on the month and time of day when energy is delivered. Table 4 shows the price adjustment established in the SOP for each month for the Super Peak, Peak, and Off-Peak periods. Super Peak is defined as 4 pm to 8 pm Monday through Saturday; Peak is defined as 6 am to 4 pm and 8 pm to 10 pm Monday through Saturday; and Off-Peak as all other times, including statutory holidays.

TABLE 4 BC HYDRO PRICE ADJUSTMENT SUMMARY FOR SOP.

Plant Design Flow [m3/s] 10 20 30 40 50 60 70 80 90 100 110 120

Installed Capacity [KW] 600 1,200 1,800 2,400 3,000 3,600 4,200 4,800 5,400 6,000 6,600 7,200

Capacity Factor 86% 83% 79% 75% 70% 65% 60% 55% 50% 46% 42% 39%

Mean Annual Energy Generation [GWh] 4.4 8.6 12.2 15.4 18.0 20.1 21.6 22.6 23.3 23.7 24.0 24.2

Estimated Capital Cost [$m] $13.14 $17.06 $20.92 $24.74 $28.54 $32.33 $36.1 $39.87 $43.63 $47.38 $51.12 $54.87

Rate Jan Feb Mar April May June July Aug Sept Oct Nov Dec

Super Peak 141% 124% 124% 104% 90% 87% 105% 110% 116% 127% 129% 142%

Peak 122% 113% 112% 95% 82% 81% 96% 101% 107% 112% 112% 120%

Off-Peak 105% 101% 99% 85% 70% 69% 79% 86% 91% 93% 99% 104%


Energy is assumed to generated evenly throughout each month. Based on the average distribution of Super Peak, Peak, and Off-Peak hours, including stat holiday effects, the ratio of the time of delivery periods is:

Super Peak 14% Peak 42% Off-Peak 44%.

5.3 ESTIMATION OF CAPITAL COST

For this exercise a Class D cost estimate was used, which is defined at the following:

“Based upon a statement of requirements, and an outline of potential solutions, this estimate is strictly an indication (rough order of magnitude) of the final project cost, and should be sufficient to provide an indication of cost and allow for ranking all the options being considered.”

The capital cost estimates were based on in-house estimated quantities and unit rates. Additionally, a ball park quote for the electromechanical generating equipment was provided by Pierre Duflon at Andritz Hydro. Of the items listed on the cost estimates, some were fixed costs, some were variable costs and others were based on percentages of the subtotal. A preliminary quantity take-off and cost estimate for the conceptual project is included in Appendix C.

5.4 OPERATING COSTS Base case operating costs are shown in Table 5. All operating costs are assumed to escalate at inflation.

TABLE 5 OPERATING COSTS.

5.5 CAPITAL STRUCTURE, FINANCING COSTS AND RESERVE ACCOUNTS The project is assumed to be financed with the maximum reasonable leverage at currently available interest rates. Interest rates for projects of this type are typically based on the yield on 30 year Canada bonds, plus a premium or spread. Long Canada bond rates are currently at or less than 3%, which is well below historic averages. Spreads for projects of this type are currently 300 basis points or an additional 3%, so the base case interest rate is assumed to be 6%.

Item Annual Cost in 2014 Note

Operations and Maintenance $214,000

Management and Administration $85,500

Insurance $26,500

Municipal and Regional Taxes $171,000

Water Taxes – Capacity $15,000 Based on $4,148 per MW

Water Taxes – Production $29,900 Based on $1.245 per MWh

Contingencies $27,000 Based on 5% of above costs

Maintenance Reserve Account $31,800


Lenders will typically establish acceptable leverage amounts based on the project’s debt service coverage ratio. The coverage ratio is defined as net operating income divided by debt service costs. For a project to be able to meet its debt service costs, the coverage ratio must be at least 1.0. Lenders will typically prefer a target debt coverage ratio of at least 1.40 or 1.45, depending on other risk factors such as complexity of construction, the type of construction contract, and other factors. There is also typically a ceiling on acceptable leverage amounts, and 85% leverage is considered a current rule-of-thumb for the allowable maximum.

The proforma also includes interest during construction at 6%, based on a bell curve distribution of construction costs over the estimated 18 month construction period. The cumulative interest costs are added to the total project costs. The base case analysis also includes a $750,000 grant to cover miscellaneous owner’s rep costs. This grant is considered representative of the funding available from external sources to support a project in this area.

As noted above, this analysis assumes the operation of the plant will fund two reserve accounts. The first, the Operating Costs Reserve Account (OCRA), is to cover shortfalls in gross revenue for those months when there aren’t sufficient revenues available to cover operating costs and debt service costs. For the base case, we have assumed that the minimum balance of this account is equal to the previous two months operating costs, so the required balance of the account is approximately $100,000 when operations begin in 2014. This analysis assumes that the OCRA is initially funded out of the first few months of revenues from operations.

The second reserve account is the Debt Service Reserve Account (DSRA). This account gives additional security to the project’s lenders that the project will make its debt service payments. This analysis assumes that the minimum balance of the DSRA is equivalent to the previous six months’ debt service payments. The analysis assumes that the DSRA is initially funded as a part of the project’s capital budget.


6 SUMMARY OF RESULTS Under the above-described assumptions, we have assessed two configurations of the Great Central Lake project under several design capacities. The two configurations are:

1. With a permanent full-time fish screen and fish-friendly turbine; and

2. No fish screen, a 4 week shutdown period to protect downstream migrating sockeye smolts and a fish-friendly turbine.

For the first configuration, with the fish screen installation included, project costs for a 70 m3/s second design flow plant are increased by $13 million to cover the cost of the fish screen and additional associated financing charges. Total costs for this scenario are shown below.

TABLE 6 TOTAL PROJECT COSTS – FISH SCREEN CONFIGURATION

Uses Cost

Construction hard and soft costs

$36,105,000

Interest during construction

$1,757,000

Debt service reserve account funding

$618,000

Less base case grant ($750,000)

Total $37,730,000

These high capital costs would significantly reduce the relative amount of debt the project could carry. To achieve the target coverage ratio of 1.4, the project would only be able to carry debt equivalent to 55% of capital costs. The target capital structure for this project is shown below.

TABLE 7 CAPITAL STRUCTURE – FISH SCREEN CONFIGURATION

Capital Structure Cost

Debt $20,752,000

Equity $16,979,000

Total Capital $37,730,000

Equity invested in this project would earn a return of only 1.51%, so it is not considered viable. The results for the fish screen configuration are similar for all plant sizes.


Given the low returns of a plant with fish screens installed, all subsequent analysis of Great Central Lake in this report will be for a plant configuration without fish screens. There may be regulatory challenges with designing a plant in this manner, but it is the only way the project could be financially viable. With the fish screen excluded, project costs are significantly lower but the project becomes sensitive to assumptions regarding the length of the shutdown period. As a base case, we have assumed a 70 m3/s design flow plant, equivalent to 4.2 MW. This sizing provides the highest returns of the options under comparison.

The monthly power generation profile for a 4.2 MW plant assuming no shutdown period is shown in Table 8. Estimated Electricity production is based on the methodology described in Section 4. Total annual generation is 21.6 GWh.

TABLE 8 AVERAGE MONTHLY ENERGY GENERATION

With the fish screen costs excluded, the plant may be required to shut down during peak downstream sockeye migration periods to reduce fish mortality. As a base case, we have assumed that the plant is not operating during April (approximating a 4-week shutdown for sockeye smolt migration), and power generation is reduced accordingly. Total project costs for the 4.2 MW plant not including a fish screen are shown in Table 9.

TABLE 9 TOTAL PROJECT COSTS – NO FISH SCREEN

Based on the above project costs, an interest rate of 6%, and a target debt coverage ratio of 1.4, the project could support debt equal to 78% of project costs. The capital structure for this financing configuration is shown in Table 10.

Energy Jan Feb Mar April May June July Aug Sept Oct Nov Dec Average

GW.h 2.4 1.9 2 2 2.2 2 1.4 0.9 0.7 1.4 2.4 2.4 1.8

Project Elements Cost

Construction hard and soft costs 23,085,000$

Interest during construction 1,124,000$

Debt service reserve account funding 636,000$

Less base case grant (750,000)$

Total 24,095,000$


TABLE 10 CAPITAL STRUCTURE – NO FISH SCREEN

The equity IRR under this configuration would be 7.2%. During the initial years of the project’s operation, equity distributions are typically paid in February and March, and total approximately $350,000 per year. No excess cash flow is available during the rest of the year. By the end of the 40 year electricity purchase agreement, annual equity distributions grow to over $500,000 and are typically paid between January and May.

Sample cash flows for the first twelve months of operations are shown in Appendix A. This is an atypical period, as the Operating Costs Account receives its initial funding in June 2014, and cash available for distributions in early 2015 is correspondingly reduced. Sample cash flows for 2017, which can be considered a typical year of operations, are shown in Appendix B.

Capital Structure Value

Debt $ 19,275,000

Equity $ 4,819,000

Total Capital $ 24,094,000


7 SENSITIVITY ANALYSIS Sensitivity analysis results for a variety of alternative scenarios are shown in Table 11. Please note that changing many of these inputs may affect project returns through several mechanisms. If the changed assumptions are known before the project is financed and built (as several of them would be), they may affect how much debt the project can take on. For this stage of analysis we have held the leverage amount constant.

TABLE 11 SUMMARY OF SENSITIVITY ANALYSIS

While the current dam is considered safe, it may require additional investment in future to ensure safe and reliable operation. To accommodate future costs to replace or maintain this facility, a reserve funding of $150,000 per year was assessed. This level of funding is considered a low bookend amount, given replacement costs for the current structure could exceed $10 million. Given this level of maintenance reserve account funding for the full term of the project, the equity IRR would be reduced to 3.2%.

Project Design IRR

Full Fish Screen / No April Shut down 1.51%

No April Shut down / No Fish Screen 10.60%

Shutdown for 75% of April / No Fish Screen 8.10%

April Shut down / No Fish Screen 7.20%

+ Interest rate 5.5% 8.60%

+ Interest rate 6.5% 5.70%

+ Contingency 20% 10.30%

+ Contingency 40% 6.40%

- 10% Longterm hydrology 3.5%

+ 10% Longterm hydrology 12.3%


8 ELSIE LAKE ENERGY RECOVERY PROJECT For comparative purposes, we examined the option of redevelopment and energy recover of the current discharge structure on Elsie Lake Dam, part of the BC Hydro Ash River Development.

Most inflows to Elsie Lake are diverted and used to generate power at the 25.2 MW Ash River Power Facility on the shores of Great Central Lake. Elsie Lake Reservoir is operated to maximize power production and ensure instream flow releases to the Ash River. Generally the reservoir is drawn down over the summer period and refilled with fall and winter run-off. Under the WUP, flow releases to the upper Ash River flows are 3.5 m3/s from May 1st to October 31st and 5.0 m3/s from November 1st to April 30th. There is also a provision for 2 pulse flows (10 m3/s for 48 hours) to enhance summer steelhead passage at Dickson Falls.

Under the current Water-use Plan (WUP) for the Ash River, instream flows are released from Elsie Lake via an outlet structure through the dam terminating with a 2.44 m dia. hollow-cove valve (HCV) into the Ash River. These HCV release flows could be discharged through a small hydro turbine to recover energy, and offered through the existing BC Hydro Standing Offer Program (SOP) for green renewable energy.

A post-WUP daily average HCV and reservoir elevation data set was provided by BC Hydro for the period of 2001 to 2010 (incomplete). A small spreadsheet was assembled assuming typical head losses head (5%) and water-to-wire energy efficiencies (85%). Net head from the centerline of the HCV to the reservoir surface was applied to the released HCV flow on the day. Notional maximum turbine capacity and minimum spin flows were included, and total annual GWh estimates were calculated from 2001 to 2010.

A range of maximum diversion rates were examined to determine the capacity factor and maximum capacity of hydro turbine/generation system. Maximum generation flows, gross head values and unit efficiencies would guide selection of the type of hydro turbine for this application. The 10 year data set was run annually and net energy production averaged over the period. The analyses indicate a small 650 kW Kaplan unit with a maximum capacity of 5 to 6 m3/s is most economical on a gross head of approximately 20 m.

We have assumed operating costs are limited to water taxes plus $5,000 in annual O&M costs. Power generation estimates are based on current flows through the existing hollow core valve to maintain instream flow requirements. A single 650 kW Kaplan unit was determined to be the optimal size given this application; annual generation is approximately 3.0 GWh and total project costs are estimated at $5.2 million, including $4.9 million in construction hard costs (not including interconnection) and an additional $300,000 in interest during construction and other financing costs. Capital structure, financing costs and reserve account requirements are assumed to be the same as for Great Central Lake.

Revenues from Elsie Lake HCV flows would support leverage of up to 82% given project costs of $5.2 million and a minimum coverage ratio requirement of 1.4. This would require equity funding of $930,000. The equity IRR under this configuration would be 7.8%. During the initial years of the project’s operation, equity distributions are typically paid between January and April and total $50,000 to $70,000 per year given 82% leverage. No excess cash flow is available during the rest of the year. By the end of the 40 year electricity purchase agreement, annual equity distributions under this capital structure grow to over $150,000 and are received in several instalments.


Increasing the proportion of equity funding would reduce the equity return. With equity funding of 50%, the equity IRR would be 6.9%. Equity distributions under this capital structure are typically $165,000 per year and are paid throughout the year. By the end of the electricity purchase agreement, annual equity distributions under this capital structure grow to over $280,000. Sample cash flows for the first twelve months of operations assuming leverage of 82% and equity funding of $930,000 are shown in Appendix D. Sample cash flows for 2017, which can be considered a typical year of operations, are shown in Appendix E.


9 SUMMARY A conceptual design, optimization and financial proforma of a hydroelectric project on Great Central Lake Dam was performed. An operational model was developed to estimate daily power generation and project optimization techniques were used to determine a notional plant capacity for the detailed financial proforma model. Preliminary quantity take-offs and scaling were used to estimate construction and equipment costs to a Class D level. Further optimization of the plant size would likely take place during detailed design.

Capital costs associated with construction of a project are relatively high ranging from $5.8M to $3.8M per MW installed. Conceptual costs to provide fish protection with permanent screens, additional fish passage with fishways and fish barrier at the tailrace add to the already high capital costs. This assessment also considered scenarios where no fish screens were installed at the intake, but plant operations are curtailed to protect downstream smolt migration.

The optimum plant size identified was approximately 4.2 MW at a flow of 70 m3/s, and utilizing the sixteen year historical hydrological data string, the proposed plant produces an average of 21.6±3.4 GWh per year. The range provided is ± one (1) standard deviation in the expected hydrology. Excluding fish screens and shutting down for the month of April was found to be more attractive than installing screens and continuing operation during this time. Both options include installation of a fish-friendly turbine that minimizes injury and mortality of fish passing through the turbine.

Under the above described configuration, with the highest acceptable leverage (which would deliver the highest possible returns), the equity IRR was determined to be 7.2%. Similar analysis was conducted for the energy recovery opportunity on the Elsie Lake HCV using the same leverage assumptions and financing costs, and reduced operating costs to reflect the simpler plant configuration. The project would require equity funding of $1.2 million and would earn an equity return of 5.8%.


10 REFERENCES Province of BC, 2011. Clean Energy Production in BC: An Inter-agency Guidebook for Proponents.

Available at: http://www.agf.gov.bc.ca/clad/IPP_guidebook.pdf.

Sigma Engineering. 1999. Great Central Lake Dam Prefeasibility Study for Hydroelectric Development. Prepared for Pacifica Papers Ltd. E5951. October 1999.

10.1 PERSONAL COMMUNICATION

Larry Cross, Catalyst Papers Ltd., meeting 31 October 2011.

http://www.agf.gov.bc.ca/clad/IPP_guidebook.pdf


APPENDIX A – GCL SAMPLE CASH FLOWS, JULY 2014 TO JUNE 2015


2014 2014 2014 2014 2014 2014 2015 2015 2015 2015 2015 20151-Jul-14 1-Aug-14 1-Sep-14 1-Oct-14 1-Nov-14 1-Dec-14 1-Jan-15 1-Feb-15 1-Mar-15 1-Apr-15 1-May-15 1-Jun-15

Gross RevenuesMW.h 1,417 887 659 1,404 2,361 2,360 2,386 1,869 1,998 - 2,212 1,986 Price per MW.h 97.73 104.13 110.18 115.11 118.28 126.32 128.83 120.13 118.70 101.00 85.58 84.17 Total Revenue 138 92 73 162 279 298 307 224 237 - 189 167

Operating CostsO&M 18 18 18 18 18 18 18 18 18 18 18 18 Management 7 7 7 7 7 7 7 7 7 7 7 7 Insurance 2 2 2 2 2 2 2 2 2 2 2 2 Municipal Taxes 14 14 14 14 14 14 15 15 15 15 15 15 Water Taxes 3 2 2 3 4 4 4 4 4 1 4 4 Contingencies 2 2 2 2 2 2 2 2 2 2 2 2 Maintenance Reserve 3 3 3 3 3 3 3 3 3 3 3 3 Total Operating Costs 49 49 48 49 51 51 52 51 51 48 52 51

Net Operating Income 89 44 24 112 229 247 256 173 186 (48) 138 116

OPERATING COSTS ACCOUNTOpening - - - 24 97 98 100 101 103 103 54 100 Additions 49 49 73 122 51 53 53 52 52 - 97 52 Less Operating Costs (49) (49) (48) (49) (51) (51) (52) (51) (51) (48) (52) (51) Closing - - 24 97 98 100 101 103 103 54 100 100

Net Cash after OCA 89 44 - 39 228 245 254 172 186 - 93 116 DEBT SERVICE ACCOUNT

Opening 618 604 544 441 377 501 643 540 609 691 588 577 Additions 89 44 - 39 228 245 - 172 186 - 93 116 Less Debt Service (103) (103) (103) (103) (103) (103) (103) (103) (103) (103) (103) (103) Closing 604 544 441 377 501 643 540 609 691 588 577 589

Net Cash - - - - - - 254 - - - - -


APPENDIX B – GCL SAMPLE CASH FLOWS, 2017


2017 2017 2017 2017 2017 2017 2017 2017 2017 2017 2017 20171-Jan-17 1-Feb-17 1-Mar-17 1-Apr-17 1-May-17 1-Jun-17 1-Jul-17 1-Aug-17 1-Sep-17 1-Oct-17 1-Nov-17 1-Dec-17

Gross RevenuesMW.h 2,386 1,869 1,998 - 2,212 1,986 1,417 887 659 1,404 2,361 2,360 Price per MW.h 131.42 122.54 121.08 103.03 87.30 85.87 100.69 107.29 113.52 118.59 121.87 130.14 Total Revenue 314 229 242 - 193 171 143 95 75 167 288 307

Operating CostsO&M 19 19 19 19 19 19 19 19 19 19 19 19 Management 8 8 8 8 8 8 8 8 8 8 8 8 Insurance 2 2 2 2 2 2 2 2 2 2 2 2 Municipal Taxes 15 15 15 15 15 15 15 15 15 15 15 15 Water Taxes 5 4 4 1 4 4 3 3 2 3 5 5 Contingencies 2 2 2 2 2 2 2 2 2 2 2 2 Maintenance Reserve 3 3 3 3 3 3 3 3 3 3 3 3 Total Operating Costs 54 53 53 50 54 53 52 52 51 52 54 54

Net Operating Income 260 176 189 (50) 139 117 90 44 23 114 234 253 Coverage Ratio 1.28 1.28 1.28 1.28 1.28 1.29 1.29 1.29 1.29 1.29 1.29 1.29

OPERATING COSTS ACCOUNTOpening 104 106 107 107 57 104 104 107 55 79 103 104 Additions 55 54 54 - 101 54 55 - 75 77 55 56 Less Operating Costs (54) (53) (53) (50) (54) (53) (52) (52) (51) (52) (54) (54) Closing 106 107 107 57 104 104 107 55 79 103 104 106

Net Cash after OCA 258 175 188 - 92 117 87 95 - 90 233 251 DEBT SERVICE ACCOUNT

Opening 611 766 663 559 456 445 459 443 435 331 318 448 Additions 258 - - - 92 117 87 95 - 90 233 251 Less Debt Service (103) (103) (103) (103) (103) (103) (103) (103) (103) (103) (103) (103) Closing 766 663 559 456 445 459 443 435 331 318 448 595

Net Cash - 175 188 - - - - - - - - -


APPENDIX C – GCL CAPITAL COSTS


No. Item A UR Quantity Subtotal Total1 General and In-directs $1,460,000

Mobilization and demobilization LS $700,000 1 $700,000Bonds and Insurance LS $20,000 1 $20,000Permits and Approvals LS $80,000 1 $80,000Testing and commissioning LS $100,000 1 $100,000Environmental LS $300,000 1 $300,000Safety LS $60,000 1 $60,000Site indirects LS $200,000 1 $200,000

2 Site Preparation and access $161,500Clearing and Grubbing ha $10,000 3 $30,000Survey and geotech investigations LS $50,000 1 $50,000road construction m $50 1,000 $50,000hazard tree removal LS $2,000 1 $2,000lay-down area clear & grade LS $25,000 1 $25,000Invasive vegetation removal LS $2,500 1 $2,500misc. water control LS $2,000 1 $2,000

3 Powerhouse Building and Tailrace $3,483,665Powerhouse Building (Colony) LS $500,000 1 $500,000Crane LS $186,667 1 $186,667Structural concrete m3 $1,200 892 $1,069,992Dewatering LS $20,000 1 $20,000Earth excavation m3 $15 1,667 $25,000Rock excavation m3 $100 1,667 $166,667Foundation treatment (cut-off, grout etc.) LS $5,000 1 $5,000Secondary Fishway for tailrace LS $1,083,333 1 $1,083,333Fencing m $100 100 $10,000Rip Rap m3 $100 83 $8,333Grouted rip rap m3 $150 83 $12,500Backfill m3 $60 714 $42,840Piping, miscellaneous metals, tubing etc. LS $20,000 1 $20,000T/G Installation LS $333,333 1 $333,333

4 Intake Structure $1,038,300Gates and controls – Headgates ea. $12,000 2 $24,000Penstocks between Headgate and Powerhouse m $500 20 $10,000Structural concrete – Intake m3 $1,200 600 $720,000Intake – misc. metals LS $1 20,000 $20,000Trashrack LS $1 100,000 $100,000Trashrake LS $1 100,000 $100,000Riprap m3 $85 80 $6,800Grouted rip rap m3 $150 50 $7,500Diversion /Cofferdam LS $50,000 1 $50,000

5 Water To Wire Generating Equipment $7,958,750Turbine and Generation MW $1,200,000 4 $5,040,000Control and Protection LS $2,000,000 1 $2,000,000Switchyard MW $218,750 4 $918,750


No. Item A UR Quantity Subtotal Total6 Fish Screen and supporting equipment $8,400,000

Fishscreen cms $120,000 70 $8,400,000

7 Transmission lines $75,000Civil component only km $25,000 1 $25,000Transmission lines km $50,000 1 $50,000

8 Communication $50,000Control sensors, camera's etc... LS 50000 1 $50,000

9 Habitat Compensation $100,000Habitat Compensation LS 100000 1 $100,000

10 Other $20,000Misc. LS $20,000 1 $20,000

Subtotal $22,747,215 $22,747,215

10 Additional Costs and Contingencies $13,357,488Contractor Profit (15% on total minus building minus w-t-w) % $5,643,465 15% $846,520Owners Cost % $22,747,215 10% $2,274,721Owner contingency % $22,747,215 5% $1,137,361Engineering % $22,747,215 10% $2,274,721Class D contingency % $22,747,215 30% $6,824,164

Subtotal $13,357,488

TOTAL CAPITAL COST $36,104,703


APPENDIX D – ELSIE LAKE SAMPLE CASH FLOWS, JULY 2014 TO JUNE 2015


2014 2014 2014 2014 2014 2014 2015 2015 2015 2015 2015 20151-Jul-14 1-Aug-14 1-Sep-14 1-Oct-14 1-Nov-14 1-Dec-14 1-Jan-15 1-Feb-15 1-Mar-15 1-Apr-15 1-May-15 1-Jun-15

Gross RevenuesMW.h 227 198 117 161 345 357 356 277 246 233 267 260 Price per MW.h 97.73 104.13 110.18 115.11 118.28 126.32 128.83 120.13 118.70 101.00 85.58 84.17 Total Revenue 22 21 13 19 41 45 46 33 29 24 23 22

Operating CostsO&M 0 0 0 0 0 0 0 0 0 0 0 0 Management - - - - - - - - - - - - Insurance - - - - - - - - - - - - Municipal Taxes - - - - - - - - - - - - Water Taxes 1 1 0 0 1 1 1 1 1 1 1 1 Contingencies - - - - - - - - - - - - Maintenance Reserve - - - - - - - - - - - - Total Operating Costs 1 1 1 1 1 1 1 1 1 1 1 1

Net Operating Income 21 20 12 18 40 44 45 32 28 23 22 21

OPERATING COSTS ACCOUNTOpening - - - 2 1 2 2 2 2 1 2 1 Additions 1 1 3 - 2 1 1 1 - 2 - 2 Less Operating Costs (1) (1) (1) (1) (1) (1) (1) (1) (1) (1) (1) (1) Closing - - 2 1 2 2 2 2 1 2 1 2

Net Cash after OCA 21 20 10 19 39 44 44 32 29 22 23 20 DEBT SERVICE ACCOUNT

Opening 120 118 114 101 96 112 132 153 130 135 134 133 Additions 21 20 10 19 39 44 44 - 29 22 23 20 Less Debt Service (23) (23) (23) (23) (23) (23) (23) (23) (23) (23) (23) (23) Closing 118 114 101 96 112 132 153 130 135 134 133 130

Net Cash - - - - - - - 32 - - - -


APPENDIX E – ELSIE LAKE SAMPLE CASH FLOWS, 2017


2017 2017 2017 2017 2017 2017 2017 2017 2017 2017 2017 20171-Jan-17 1-Feb-17 1-Mar-17 1-Apr-17 1-May-17 1-Jun-17 1-Jul-17 1-Aug-17 1-Sep-17 1-Oct-17 1-Nov-17 1-Dec-17

Gross RevenuesMW.h 356 277 246 233 267 260 227 198 117 161 345 357 Price per MW.h 131.42 122.54 121.08 103.03 87.30 85.87 100.69 107.29 113.52 118.59 121.87 130.14 Total Revenue 47 34 30 24 23 22 23 21 13 19 42 46

Operating CostsO&M 0 0 0 0 0 0 0 0 0 0 0 0 Management - - - - - - - - - - - - Insurance - - - - - - - - - - - - Municipal Taxes - - - - - - - - - - - - Water Taxes 1 1 1 1 1 1 1 1 0 0 1 1 Contingencies - - - - - - - - - - - - Maintenance Reserve - - - - - - - - - - - - Total Operating Costs 1 1 1 1 1 1 1 1 1 1 1 1

Net Operating Income 46 33 29 23 22 21 22 20 12 18 41 45 Coverage Ratio 1.17 1.17 1.18 1.18 1.18 1.18 1.18 1.18 1.18 1.18 1.18 1.18

OPERATING COSTS ACCOUNTOpening 2 2 2 1 2 1 2 2 1 2 1 2 Additions 1 1 - 2 - 2 1 - 2 - 2 2 Less Operating Costs (1) (1) (1) (1) (1) (1) (1) (1) (1) (1) (1) (1) Closing 2 2 1 2 1 2 2 1 2 1 2 2

Net Cash after OCA 45 33 30 22 23 20 22 21 12 19 40 45 DEBT SERVICE ACCOUNT

Opening 149 125 135 141 118 118 114 113 111 99 95 111 Additions - 33 30 - 23 20 22 21 12 19 40 45 Less Debt Service (23) (23) (23) (23) (23) (23) (23) (23) (23) (23) (23) (23) Closing 125 135 141 118 118 114 113 111 99 95 111 133

Net Cash 45 - - 22 - - - - - - - -

somass basin hydro assessment - british...

Documents