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Available Project Finance Models with CDM and Renewable Energy Law Incentives

January 15th, 2010 Posted in financial models

Available Project Finance Models with CDM and Renewable Energy Law Incentives

I just finished polishing all my project finance models for the following power generation technologies and are now available for actual runs by project developers, researchers and individuals doing business development.  Using the models below will allow user to determine as quickly as possible the “best new entrant” technology applicable to a particular location given the fuel and energy resource available and the electricity tariff prevailing in the area.

1) Biomass (direct combustion, co-firing with fossil coal and oil, municipal solid waste, sewage digestion or biogas, biomass gasification)

2) Cogen (power, heat) – coal, oil, natural gas

3) Mini-Hydro

4) Wind Farm

5) Solar PV

6) Diesel engine (diesel, gas oil, bunker, orimulsion)

7) Thermal (Rankin Steam Cycle) – Oil, Coal, Gas

8) Geothermal

9) Simple Cycle and Combined Cycle Gas Turbine

10) Hybrid (Diesel plus Biomass, Mini-hydro, wind or solar)

11) Incremental Economic Analysis (base case vs alternative case such as conversion from diesel engine power plant to natural gas-fired engine power plant)

12) Circulating Fluidize Bed (CFB) – lignite, coal, biomass

13) On the drawing board (future models for energy storage, solar thermal, fuel cells, ocean thermal, ocean wave, tidal power and nuclear)

All the above models include incentives under the new Renewable Energy Law and CDM under the Kyoto Protocol.  The user may opt to change the incentives prevailing in their locality.

The model includes: leap year and non-leap year, capacity degradation, overhaul and regular maintenance cycles, downtimes (economic S/D, external trips, internal trips), availability and operating hours, reliability, load factor, capacity factor, gross generation, losses (step-up transformer, transmission line, distribution line), net sales, plant heat rate and efficiency degradation, fuel mix blending, fuel consumption per type of fuel, cost per type of fuel, electricity tariff (direct customers, grid, spot market), total revenues, fuel costs, variable O&M, fixed O&M, regulatory costs (taxes, licenses, registration fees), property insurance, business interruption insurance, DSRF expense, total expenses, gross margin, depreciation, interest payment, income before income tax, income tax, income after income tax, principal repayment, DSRF income, CDM cash flows (carbon emission reduction net of monitoring fees), cash flow, DCF IRR (as DCF-ROI, DCF-ROE, DCF-FC, DCF-FC discounted), working capital needs, all-in project cost [land, building & civil works, power plant & accessories, installation, project development, registration & regulatory costs and other capitalized expenses, capitalized working capital (mobilization & training, initial stocks of fuels and supplies, plant trials & commissioning) and capitalized interest cost during construction], evolution of balance sheet accounts (land, fixed assets, capitalized expenses), loan amortization table (principal and interest), debt service reserve fund, balance sheet, statement of cash flows, income statement, levelized price and levelized generation cost breakdown, summary of operations & financial reports, and project graphics (gross margin, income after tax, cash flow for debt service, debt service and annual dividends versus year of operation).

By considering the effect of plant location on delivered cost of fuel, type of cooling system (once thru sea water, once thru lake water, river water cooling tower, deep well water cooling tower, radiator or dry cooling) and its pumping costs and pumping energy, type of transmission line (type, length, conductor type) and its energy losses, and impact of plant location of the machine’s power output (effect of elevation and atmospheric pressure, ambient air temperature and humidity), it is possible to determine during the preliminary feasibility study the optimal power plant location.

The user may consider also escalation of electricity tariff, fuels, variable O&M, fixed O&M and regulatory costs.  Finally, the analysis may also consider the impact of the depreciation of the local currency (electricity tariff and operating costs) on net cash flow versus the foreign currency denominated project cost.  As an example, discounting of the cash flows will protect the dollar investments from depreciating peso revenues.

Since these models determine the first year electricity tariff needed to meet generation cost, recover capital cost and earn reasonable profit needed by an investor to risk his capital, these models will be helpful in determining the feed-in tariff (FIT) needed to encourange the development of renewable energy sources. By its very nature, renewable energy sources are more expensive than the average grid tariff, hence, the guaranteed payment of a feed-in tariff for a minimum number of 15-25 years will surely encourage greater use of renewalbe energy that will not only conserve scarce fossil fuel but also mitigate global warming by reducing greenhouse gas emissions such as CO2 from power plants and methane from landfills left to rot.

For more information, please contact the author below.

Marcial T. Ocampo

Energy Technology & Business Development Consultant

Project Finance & Financial Modeling

Market, Technical & Feasibility Studies

email mars_ocampo@yahoo.com

energydataexpert@gmail.ocm

web   www.energytechnologyexpert.com

http://ph.linkedin.com/in/ocampomarcial

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