ECONOMIC AND FINANCIAL EVALUATION
STUDY:
GUYANA - AMAILA FALLS HYDRO
PROJECT
REPORT
Prepared for:
Government of Guyana
November, 2009
Revised March 2010 – Final version
R1056-09 A0078
ECONOMIC AND FINANCIAL EVALUATION STUDY:
GUYANA - AMAILA FALLS HYDRO PROJECT
CONTENTS
FOREWORD .......................................................................................................................................... 5
EXECUTIVE SUMMARY........................................................................................................................ 7
1.
2.
3.
4.
5.
6.
GENERAL FRAMEWORK ............................................................................................................... 7
DEMAND FORECAST .................................................................................................................... 8
LEAST COST EXPANSION PLAN ..................................................................................................... 9
COST-BENEFIT ANALYSIS .......................................................................................................... 10
COMPETITIVENESS OF AMAILA FALLS ........................................................................................ 12
SENSITIVITY ANALYSIS .............................................................................................................. 14
6.1.
CRUDE OIL PRICES ......................................................................................................... 14
6.2.
MARKET EXPANSION ....................................................................................................... 15
7. REVIEW ON HYDROLOGY STUDIES AND PLANT DESIGN ................................................................. 16
8. MAIN CONCLUSIONS ................................................................................................................. 18
SECTION I: FUNDAMENTALS OF THE ANALYSIS.......................................................................... 22
1.
2.
3.
INTRODUCTION ......................................................................................................................... 22
ECONOMIC RATIONALE .............................................................................................................. 22
PROJECT BACKGROUND ............................................................................................................ 23
3.1.
AMAILA FALLS PHYSICAL SETTING .................................................................................. 23
3.2.
GUYANA POWER SECTOR OVERVIEW ............................................................................... 24
3.2.1. Self generation ................................................................................................................25
3.2.2. Linden area .....................................................................................................................26
SECTION II: DEMAND FORECAST.................................................................................................... 27
1.
ELECTRICITY DEMAND DRIVERS ................................................................................................. 27
1.1.
MACROECONOMIC GROWTH ............................................................................................ 27
1.2.
EXTRA-TENDENCY GROWTH IN THE SHORT RUN ............................................................... 27
2. REGRESSION MODELS .............................................................................................................. 28
2.1.
FORECAST OF THE INDEPENDENT VARIABLE (GDP).......................................................... 29
2.2.
ELECTRICITY DEMAND PROJECTION (GPL) ...................................................................... 30
2.3.
ELECTRICITY DEMAND IN LINDEN AREA ............................................................................ 33
2.4.
SELF-GENERATION ......................................................................................................... 33
SECTION III: COST-BENEFIT ANALYSIS FOR AMAILA FALLS PROJECT................................... 35
1.
2.
LEAST COST EXPANSION PLAN ................................................................................................... 35
KEY ASSUMPTIONS ................................................................................................................... 36
2.1.
DEMAND FORECAST ....................................................................................................... 36
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
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2.2.
FUEL PRICES .................................................................................................................. 38
2.3.
TYPE OF TECHNOLOGY TO EXPAND THE POWER SYSTEM................................................... 38
2.4.
COSTS OF AMAILA FALLS PROJECT ................................................................................. 40
3. LEAST COST EXPANSION PLAN ................................................................................................... 41
3.1.
NEW GENERATING CAPACITY........................................................................................... 42
3.2.
EXPECTED DISPATCH OF POWER PLANTS ......................................................................... 43
4. COST-BENEFIT ANALYSIS ........................................................................................................... 45
4.1.
COST STREAM ................................................................................................................ 45
4.2.
BENEFIT STREAM............................................................................................................ 45
4.2.1.
4.2.2.
4.2.3.
4.2.4.
4.3.
4.4.
4.5.
Direct savings in fuel consumption..................................................................................45
Direct savings in O&M of thermal generation fleet ..........................................................46
Direct savings in capital expenditures in new thermal facilities .......................................46
Carbon emissions reduction............................................................................................47
COSTS AND BENEFITS STREAM ........................................................................................ 47
NET PRESENT VALUE OF THE PROJECT AND ECONOMIC RATE OF RETURN ........................... 48
OPPORTUNITY COST FOR GPL (MAXIMUM ANNUAL FIXED PAYMENT) ................................. 55
SECTION IV: COMPETITIVENESS OF AMAILA FALLS SUPPLY COST ........................................ 56
5.
6.
GPL SUPPLY COST................................................................................................................... 56
COST OF SELF GENERATION ...................................................................................................... 57
SECTION V: SENSITIVITY ANALYSIS............................................................................................... 59
7.
8.
SENSITIVITY TO CRUDE OIL PRICE .............................................................................................. 59
SENSITIVITY TO MARKET EXPANSION .......................................................................................... 60
8.1.
UPSIDE CASE ................................................................................................................. 60
8.2.
DOWNSIDE CASE ............................................................................................................ 61
SECTION VI: REVIEW OF EXISTING HYDROLOGY STUDIES........................................................ 62
SECTION VII: MAIN CONCLUSIONS ................................................................................................. 64
ANNEX I – SIMULATION MODEL OUTPUTS .................................................................................... 67
ANNEX II – SELF GENERATORS SURVEY ...................................................................................... 74
ANNEX III – REVIEW OF EXISTING HYDROLOGY STUDIES.......................................................... 86
1.
2.
3.
4.
EXECUTIVE SUMMARY ............................................................................................................... 87
INTRODUCTION ......................................................................................................................... 88
PROJECT DESCRIPTION ............................................................................................................. 88
SUMMARY OF KEY PROJECT FEATURES ..................................................................................... 89
4.1.
DAMS AND SPILLWAY ...................................................................................................... 89
4.1.1. Amaila Dam.....................................................................................................................89
4.1.2. Kuribrong Dam ................................................................................................................90
4.2.
4.3.
4.4.
4.5.
4.6.
4.7.
4.8.
INTAKE AND HEADRACE TUNNEL ..................................................................................... 90
SURGE AND POWER SHAFT ............................................................................................ 90
POWER TUNNEL ............................................................................................................. 90
LOWER HEADRACE TUNNEL AND SURFACE PENSTOCK ALTERNATIVE ............................... 90
POWERHOUSE ............................................................................................................... 91
TAILRACE CHANNEL ....................................................................................................... 91
SWITCHYARD ................................................................................................................. 91
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
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4.9.
KURIBRONG BRIDGE ....................................................................................................... 91
HYDROLOGY ASPECTS.............................................................................................................. 91
5.1.
SITUATION OF AMAILA PROJECT...................................................................................... 92
5.2.
TOPOGRAPHY AND CONTRIBUTING BASINS DRAINAGE ....................................................... 92
6. OBTAINING THE RESERVOIR’S HYDROLOGY PARAMETERS............................................................ 93
6.1.
DETERMINATION OF AVERAGE MONTHLY AND ANNUAL FLOWS ........................................... 93
6.2.
RESERVOIR EVAPORATION .............................................................................................. 95
6.3.
PROBABLE MAXIMUM FLOW – OPERATION PERIOD ........................................................... 96
5.
6.3.1.
6.3.2.
6.3.3.
6.3.4.
6.3.5.
6.3.6.
6.3.7.
6.3.8.
Estimation of the PMP.....................................................................................................96
Duration of the PMP........................................................................................................96
Temporal distribution of the PMP ....................................................................................97
Losses due to infiltration .................................................................................................97
Unitary diagram...............................................................................................................97
Transformation of PMP into PMF ....................................................................................98
Evaluation of the PMF.....................................................................................................99
Maximum design flow during the construction period......................................................99
7.
8.
9.
SEDIMENTATION ..................................................................................................................... 100
CONCLUSIONS ON HYDROLOGY ASPECTS ................................................................................. 100
DAM HEIGHT AND INSTALLED CAPACITY .................................................................................... 101
9.1.
METHODOLOGY ............................................................................................................ 101
9.2.
RESULTS ..................................................................................................................... 102
10. POSSIBILITIES OF DESIGN VARIATIONS: GENERAL COMMENTS .................................................... 107
10.1. INCREASE IN DAM HEIGHT ............................................................................................. 107
10.2. ENHANCING THE DAM’S REGULATION CAPACITY .............................................................. 107
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
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ECONOMIC AND FINANCIAL EVALUATION STUDY:
GUYANA - AMAILA FALLS HYDRO PROJECT
FOREWORD
As part of its development strategy for the next five years, the Government of Guyana
(GoG) has decided to meet its medium and long term power needs from renewable
sources.
Guyana has significant hydroelectric resources yet not developed. Amaila Falls was
identified, along with several other projects, as a potential hydro development site
during studies carried out around 1975 for the first time. In recent years, the Guyana
Energy Agency favored Amaila Falls as the first project to develop based on its location
and water flows.
Synergy Holdings, a Guyanese developer based in the US, obtained the rights to
develop Amaila Falls project, performed a feasibility study in 2002 and initiated
negotiations with the state-owned utility GPL as the primary off-taker.
In the meantime, Synergy joined forces with Enventure (US developer) and later invited
Sithe Global to look at this project opportunity.
EPC proposals received in Nov 2008 are being analyzed in parallel with a PPA to allow
acceptable yearly tariff to pass-through to final customers.
In this context, the Government of Guyana and Sithe Global retained Mercados
Energéticos Consultores to perform a comprehensive study to ensure that Amaila Falls
project is:
1. consistent with the least cost generation expansion option to assure the
economic profitability of the hydro power plant project and
2. compatible with the medium and long-term demand projections.
This Report is organized as follows:
• The Executive Summary highlights key contents of the Report;
• Section I summarizes the project background and the economic fundamentals of
the study;
• Section II describes the electricity demand forecast
• Section III analyses the least cost generation expansion plan, the cost-benefit
analysis for Amaila Falls project and its economic rate of return.
• Section IV discusses the competitiveness of Amaila Falls supply cost compared
to GPL’s alternative supply option and to self generation costs.
• Section V presents the sensitivity analysis to fuel prices and demand growth on
the economic profitability of the project.
• Section VI presents the review of the existing hydrological studies
• Finally, Section VII summarizes the main conclusions of the study.
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
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• Annexes:
9
Annex I contains tables with the outputs of the simulation model;
9
Annex II reproduces the Report done by Mr. John Cush, local consultant
retained by GPL to conduct a survey on self generators;
9
Annex III presents the review of hydrology studies and plant’s design (done
by MWH).
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
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EXECUTIVE SUMMARY
1. GENERAL FRAMEWORK
• While the development of the 154 MW Amaila Falls projects is based on the
decision to shift from costly and imported fuel sources to using the abundant,
domestic water potential, the generation expansion plan has to consider
developing the power sector in the most economically efficient manner (i.e. least
cost).
• Amaila Falls hydro project is expected to cover a significant proportion of the
existing power demands in Guyana. As such, the characteristics of the Project
must be established in light of the existing and future power system (total
installed capacity and size of individual units, power system reliability and
stability).
• The electricity sector in Guyana is dominated by Guyana Power and Light (GPL),
a vertically integrated government-owned utility.
• GPL owns and manages 142 MW of installed capacity (2009), all of which is
based on thermoelectric plants with diesel-engine driven generators, exposing
the sector to price shocks and the inherent volatility of the international oil
markets.
• Electrification in Guyana is low both in terms of access and in terms of intensity of
use relative to other countries in the region. GPL’s gross demand is estimated in
580 GWh-year (2010e).
• Losses at the distribution level account for up to 30 % of the energy generated.
At the commercial level, the utility is making efforts to enforce collection of bills,
and to eradicate theft.
• Deficiencies in power infrastructure and low reliability of service in Guyana may
pose an important constraint for the development of the country.
• According to the World Bank in its Guyana Investment Climate Assessment
Report (2007), four aspects of the investment climate were mentioned in the
group of top constraints: cost of financing, macroeconomic uncertainty, worker
skills and education, and electricity.
• A survey recently conducted among the most important self generators registered
in the Guyana Energy Agency (GEA) confirmed that self-supply of electricity in
Guyana meets a significant proportion of the country’s electricity demand (131
GWh-year, approximately 20 % of GPL’s gross demand), although it is costly and
generates economic inefficiencies.
• In the Base Case scenario, ME assumed that the total amount of self generation
surveyed decides to take power from GPL during the first 2 years of Amaila Falls
commercial operation: 60 % of 131 GWh-year in Y 2014 and the remaining 40 %
in Y 2015.
• Linden Power Company (LPC) is another major customer for Amaila Falls, as the
planned transmission line can easily be routed through Linden (66 – 70 GWhyear)
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
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2. DEMAND FORECAST
• The main driver to account for electricity demand growth is the economic activity
(GDP) which explains the natural trend in demand growth.
• ME forecasted the electricity sales by type of customer as a function of global
GDP. Different functional forms were tested for each sector and selected those
with best statistical indicators.
• Estimated total demand elasticity to GDP growth is 1.75 (i.e. a 3.0 % GDP growth
accounts for 5.2 % in demand growth). This elasticity varies among consumption
sectors: 1.4 for residential customers and 2.2 for industrial users.
• Once the econometric models were specified and its parameters estimated for
each consumption sector, ME envisaged a base case macroeconomic scenario
to forecast GDP growth:
Year
2008
2009 est
2010 est
2011
2012
2013
2014
2015
2016
2017 – 2025
2026 onwards
GDP
Growth rate%
3.1%
2.2%
2.8%
3.5%
2.8%
2.9%
2.9%
2.9%
2.9%
3.0%
3.1%
Sources: Ministry of Finance (2008 figure); own elaboration based on CEPAL and on World
Bank projections (2009 onwards)
• Besides, in the short run, there are three factors that account for an extra
tendency growth of electricity sales within GPL’s serving area:
•
9
New connections under un-served areas electrification programmes and
current construction boom
9
Reduction in non-served energy due to present generation shortfall
9
Loss reduction programme at the distribution level
Demand forecast for the Base Case is shown below:
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
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Demand Forecast
GDP growth
Total Sales GPL system
T & D losses
Year
%
2009
2.2%
2010
2.8%
2014
2.9%
2015
2.9%
2020
3.0%
2025
3.0%
2030
3.1%
2035
3.1%
GWh
annual growth
393
418
6.3%
500
5.1%
525
5.1%
677
5.2%
876
5.3%
1,140
5.5%
1,479
5.1%
in %
Technical
11.4%
10.6%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
Non-technical
21.6%
19.4%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
Gross generation GPL system
GWh
annual growth
587
597
1.7%
701
4.1%
737
5.1%
949
5.2%
1,229
5.3%
1,599
5.5%
2,073
5.1%
Linden Power Company
GWh
66
68
2.8%
76
2.9%
79
2.9%
91
3.0%
106
3.0%
123
3.1%
143
2.9%
Self generation switching to the grid
GWh
0.60
79
0.40
131
152
3.0%
176
3.0%
205
3.1%
239
3.1%
Total expected demand
Expected demand growth
GWh
%
653
665
1.8%
856
14.5%
947
10.6%
1,192
4.8%
1,511
4.9%
1,927
5.0%
2,454
4.8%
MW
MW
75
108
76
110
Average load
Peak demand
-
-
98
142
108
157
136
197
172
250
220
319
Note on GPL gross generation: Y 2009, actual figure. Y 2010, GPL estimation. From then onwards,
forecasts are based on econometric models developed by Mercados Energéticos.-
3. LEAST COST EXPANSION PLAN
• In order to estimate the economic profitability of Amaila Falls project, ME
compared the expansion of the power generation capacity of Guyana with and
without Amaila Falls project.
• The optimal (least cost) investment schedule to supply the forecasted load was
then modeled for two different situations:
1. expansion of the generation capacity fully based on thermal power plants,
typically medium speed engines or gas turbines, in both cases using liquid
fuels (HFO, LFO) and
2. expansion of the generation capacity considering that Amaila Falls hydro
project begins commercial operation in Y 2014. From then onwards, if new
capacity additions are needed, they will be thermal plants using liquid fuels.
• The objective function was to minimize the expected supply costs, including
investment, operational costs and non-supplied energy cost; subject to an
adequate reliability of the system’s operation (reserve margin).
• The results attained for each capacity expansion situation were next compared to
estimate the measurable benefits of Amaila Falls project:
•
9
Direct savings in fuel purchases for generation purposes
9
Direct savings in O&M of the thermal generation fleet
9
Direct savings in capital expenditures (new thermal facilities).
9
Carbon emissions reduction
Key assumptions are: crude oil prices, expected demand, type of technology
selected to expand generation capacity and costs of Amaila Falls project.
9
Crude oil prices directly influence the cost of HFO and LFO which, in turn,
account for most part of the variable cost of production of fuel-fired
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
9
280
406
generators. Base case assumes a WTI of 75 USD / bbl (consistent with
latest World Bank’s projections).
Crude Oil
(USD / bbl)
75
HFO (USD / bbl)
LFO (USD / bbl)
FOB
Freight
CIF
FOB
Freight
CIF
56.1
5.8
61.9
91.6
5.8
97.4
Source: own estimates based on a linear correlation of fuel prices as a function of crude
oil prices.
9
Type of technology to expand the system: ME estimated the development
cost of HFO medium speed engines and LFO-fired gas turbines. HFO
medium speed engines was the favored (least cost) technology for relative
high dispatch factors. The long run marginal cost for such technology is
around 13.0 – 14.0 ¢USD / kWh, assuming a crude oil price of 75 USD /
bbl.
9
Costs of Amaila Falls project: provided by the Client. PPA consists of a
fixed annual payment of -105,000 k USD (take-or-pay).
•
Model results for each expansion alternative analized (with and without Amaila
Falls) include: new capacity additions (size, time) necessary to meet expected
load, expected dispatch of power plants and operational costs and generation
reserve margin 1.
•
Amaila’s expected average energy production (983 GWh) is well-matched with
expected demand growth driven by existing GPL / Linden customers; and the
addition of 131 GWh-year of self generation as of 2014.
•
As of Y 2022 increasing amounts of thermal generation are needed, on top of
Amaila mean energy production, to meet expected demand and to keep a
reasonable reserve margin in the system.
4. COST-BENEFIT ANALYSIS
•
Cost stream: Fixed annual payment for Amaila Falls energy production of
105,000 k USD during 20 years.
•
Benefits stream: the economic benefits of the project were identified and
measured, by category, over the study time horizon (40 years):
9
Direct savings in fuel consumption: represent approximately 68 % of total
economic benefits (80,000 – 85,000 k USD per year).
9
Direct savings in O&M costs of thermal facilities: represent around 2 % of
total economic benefits identified (2,300 – 2,500 k USD per year).
Amaila’s output is subject, by definition, to hydro volatility (there are some months of the year
when thermal plants are needed to meet the portion of demand load that can not be met by
Amaila’s production).
1
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
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9
Direct savings in capital expenditures in new thermal units: account for
approximately 24 % of total economic benefits (29,000 k USD per year).
9
Carbon emissions reduction: add around 6,200 – 6,500 k YSD per year to
total benefits (5 %).
•
Amaila’s fixed costs are evenly distributed over 20 years while Amaila’s benefits
are mostly concentrated on medium to long term. This is variable and mostly
depends on expected market development and oil prices.
•
Annual costs and benefits are shown in the graph below:
Amaila Falls Project: Costs and Benefits Stream
160,000
Savings in O&M costs
Carbon credits
140,000
120,000
100,000
Savings in CAPEX (thermal units)
in thousand US dollars per year
80,000
60,000
Savings in liquid fuel costs
40,000
20,000
2037
2036
2035
2034
2033
2032
2031
2030
2029
2028
2027
2026
2025
2024
2023
2022
2021
2020
2019
2018
2017
2016
2015
-20,000
2014
-
-40,000
Fixed annual payment (PPA):
-105,000 k USD
-60,000
-80,000
-100,000
-120,000
Savings in Fuel Costs
•
Savings in CAPEX annual payments
Total Costs
186,886
83%
0.70
If carbon credits are not considered in the project’s benefits, the above
economic indicators are the following:
NPV (kUSD) (@ 12%)
ERR
Benefit - Cost Ratio BCR
•
Carbon Credits
Under the set of assumptions adopted, the net present value of the project cash
flow is, the economic rate of return (ERR) and the Benefit-cost ratio (BCR) are
the following:
NPV (kUSD) (@ 12%)
ERR
Benefit - Cost Ratio BCR
•
Savings in O&M Expenses
132,390
32%
0.66
It’s also worth mentioning that in the Base Case there is only one year (the first
one) of project’s cash flow when costs exceed economic benefits by 5.9 million
USD. This is so because Amaila’s fixed costs are evenly distributed over 20
years while Amaila’s benefits are mostly concentrated on medium to long term.
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
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If a more aggressive market expansion is assumed, this effect reverses,
because fixed costs are burdened by a larger demand.
•
ME also estimated the maximum fixed annual payment (GPL’s opportunity cost)
for Amaila’s output which verifies that the present value of GPL’s total
generation expenses (CAPEX and OPEX) is equal in both capacity expansion
options analyzed. The said annual fixed payment is – 122,724 k USD,
considering Base Case assumptions.
•
Even though this ceiling payment assures Amaila’s structural competitiveness
compared to GPL’s thermal expansion option (opportunity cost), it also creates
a financial constraint on GPL in the short to medium term: supply costs
including Amaila are higher than supply costs deselecting Amaila as a
candidate project.
•
In turn, high average supply costs relative to other supply choices, discourage
market expansion and increases demand risk for GPL.
•
Therefore, ME re-estimated the maximum fixed annual payment assuming a
relative more conservative scenario: no self generators decide to purchase
power from GPL (because there would be no room for tariff incentives to attract
new customers) and a higher discount rate (14%) than Base Case because
GPL’s demand risk increases. The annual fixed payment in this stressed
scenario drops to – 106,785 k USD.
•
The table below summarizes key assumptions for each estimated maximum
fixed annual payment:
Crude Oil (USD /
bbl)
Base Case
75
75
Discount Rate
12%
14%
Demand
same as Base Case
without self generators
GPL's maximum
annual payment for
Amaila's output
# of initial years
when costs
exceeds benefits
-122,724
-106,785
20
7
Note: carbon credits are not considered among total economic benefits.-
5. COMPETITIVENESS OF AMAILA FALLS
•
Amaila Falls hydro power plant project will sell its energy output primarily to
GPL, at a fixed annual payment of -105,000 k USD, regardless actual demand.
In other words, the power purchase agreement is a take-or-pay contract.
•
Amaila Falls project will be competitive if other supply options available for GPL
(or any other off-taker) have higher prices than Amaila’s supply cost (PPA).
•
Supply option for GPL: GPL’s least alternative (to Amaila Falls) supply cost is
the long run marginal cost (LRMC) of the most competitive thermal technology
available to expand its power system (bunker-fired engines). Such LRMC is in
between 13.0 and 14.0 ¢USD / kWh, estimated with the following set of
assumptions:
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
12
Expansion Technology: HFO medium speed engines
Parameter
Investment Cost
1,100 USD / kW
Return on equity
16.07 %
Repayment period
10 years
O&M
0.9 ¢USD / kWh
Type of fuel
Heavy fuel oil
Fuel cost on site
61.9 USD / bbl (Crude oil 75 USD / bbl)
Gross capacity
7 MW
40 %
Heat rate
2,158.9 kCal / kWh
56.4 Gal / MWh
Expected dispatch
2
70 %
•
Synthetic economic indicators of the cost-benefit analysis show that the
inclusion of Amaila Falls in GPL’s generation expansion plan lowers the net
present value of GPL’s generation expenses.
•
The inclusion of Amaila Falls cuts down GPL’s average supply costs to 11.5
¢USD / kWh in the medium to long term.
•
However, in the early years of the project (first year of Amaila’s operation in the
Base Case) and given that contractual arrangement is take-or-pay, GPL’s total
generating expenses including the power purchase agreement with Amaila
Falls are closer or even 5 - 10 % higher than GPL’s generation expenses
without including Amaila Falls (and only adding needed thermal generators to
meet demand growth)
•
Market expansion mitigates this short run effect because the fixed annual
payment is absorbed by a larger demand.
•
In any case, GPL’s degree of success in attracting industrial self generators
back to the grid, will depend on the tariff2 at which GPL can deliver the energy
to such customers compared to their self-generation cost.
•
Based on data collected in the self generators survey and own assumptions,
ME estimated the following costs of self-generation (assuming a crude oil price
of 75 USD / bbl):
9
between 19.3 – 20.7 ¢USD / kWh, for an industry assessing the costs of
installing a new power generator.
9
between 15.8 and 17.2 ¢USD / kWh for existing self generators (does not
include investment cost – sunk cost -, only operating costs).
Reliability of service will also play a key role in market expansion
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
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•
The above estimated self generation costs represent the break-even price for
an industrial customer, assuming same reliability in supply options (GPL vs self
generation).
•
The cost of self generation (both for prospective and existing self generators as
well) is higher than GPL’s average supply costs.
•
It’s worth noting that these figures are not directly comparable with GPL’s
supply cost (transmission and distribution charges have to be added).
6. SENSITIVITY ANALYSIS
6.1.
CRUDE OIL PRICES
•
Variable operating costs for thermal plants mostly depend on fuel costs. Direct
savings in fuel costs account for approximately 68 % 3 of total economic
benefits of Amaila Falls project.
•
Future scenarios of high crude oil prices contribute to increase the
competitiveness of Amaila Falls vis a vis the thermal expansion (upside).
Conversely, scenarios of low crude oil prices are a downside for the project.
•
The following table shows the economic indicators of the cost-benefit analysis
for different scenarios of future crude oil prices, with and without considering
carbon credits as part of the total benefits):
Sensitivity to WTI (net cash flow includes carbon credits).-
Crude Oil price NPV (@ 12%)
Base Case (*)
Downside Cases
USD / bbl
75
70
65
60
55
k USD
186,886
145,052
103,217
61,383
19,549
ERR
BCR (**)
in %
83%
37%
23%
17%
13%
0.70
0.67
0.64
0.61
0.58
# of initial years with
negative cash flow
(cost > benefits)
1
2
4
6
8
(*) consistent with World Bank's latest projections
(**) Benefit - Cost ratio = NPV (Benefits) / NPV (Costs)
Time horizon: 40 years
Sensitivity to WTI (net cash flow does not include carbon credits).-
Crude Oil price NPV (@ 12%)
Base Case (*)
Downside
Cases
USD / bbl
75
70
65
60
55
k USD
132,390
90,556
48,721
6,887
-34,947
ERR
in %
32%
21%
16%
12%
10%
BCR (**)
0.66
0.63
0.60
0.57
0.54
# of initial years with
negative cash flow
(cost > benefits)
3
5
7
8
20
Avoided costs in fuel consumption for generation purposes are in the range of 80,000 to
85,000 thousand dollars per year.
3
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
14
ERR stands for Economic Rate of Return
6.2.
MARKET EXPANSION
•
In the short run, annual fixed payment for Amaila’s output may outweigh the
direct savings in operating costs and capital expenditures in new thermal
generators. Instead, in the medium to long run benefits outweigh the costs.
•
Market expansion contributes to compensate the temporary imbalance between
total costs and total benefits.
•
The following table shows the project’s economic indicators for different
scenarios of market expansion:
Sensitivity to market expansion
Scenario
Base Case (*)
Upside Case
Self generators
switching to the grid
GWh-year
131 GWh (60 % in 2014
& 40 % in 2015)
NPV (@ 12%)
Economic rate
of return (ERR)
Benefit / Cost
ratio
k USD
in %
BCR
# of initial years with
negative cash flow
(costs larger than
benefits)
186,886
83%
0.70
195,664
positive cash flow
all years
0.71
105 GWh as of Y 2014
170,318
49%
0.69
2
79 GWh as of Y 2014
153,363
34%
0.68
3
100,870
19%
0.64
7
131 GWh as of Y 2014
1
zero
Downside Cases:
20% less than BC
40 % less than BC
Self generators decide not to switch to the grid
•
Upside case: If it is assumed that 100 % of estimated self generation (131
GWh-year) is connected to the grid during the first year (2014) of Amaila Falls
operation 4, benefits outweigh costs since the beginning (2014):
Instead of assuming that only 60 % of 131 GWh switches to the grid during the first year
(2014) and the remaining 40 % of self generation connects to the grid during the second year
(2015).- (Base Case)4
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
15
GPL's generating expenses per unit of demand
With and without Amaila Falls in the expansion plan
16.0
15.5
15.0
14.5
14.0
100 % Thermal Expansion
in cUSD / kWh
13.5
13.0
12.5
12.0
11.5
Expansion with Amaila as of Y 2014
(includes carbon credits)
11.0
10.5
10.0
Y 2014:
Amaila Falls begins commercial operations
9.5
20
36
20
37
20
34
20
35
20
32
20
33
20
30
20
31
20
28
20
29
20
26
20
27
20
24
20
25
20
23
20
21
20
22
20
19
20
20
20
17
20
18
20
15
20
16
20
13
20
14
20
11
20
12
20
09
20
10
9.0
7. REVIEW ON HYDROLOGY STUDIES AND PLANT DESIGN
•
The design of Amaila Falls Project encountered several problems arising from
the lack of hydrologic data. Therefore, the best techniques available were
applied to cope with the lack of information but even so, several questions
remained unanswered, such as the following:
9
The flows used were obtained by extrapolating the results from Kaieter
Falls Station with different transfer coefficients and then adopting 0.30
without further justification. This may cause some uncertainty regarding the
expected power generation.
9
The maximum flow adopted to design the dam was the result of
transforming the Probable Maximum Precipitation value into the Probable
Maximum Flow by adopting a C coefficient (Creaguer’s formula) that has no
direct justification, thus causing uncertainty as regards the maximum flow
adopted for the design at 5.010 m3/s.
9
In addition, the Probable Maximum Flood was assessed in the current
basin status, with no deforestation or mining exploitation. Any modification
of the basin in such respect will have an impact on the increase in the
maximum value considered.
9
The flows assumed for different return periods, which set the maximum
values to be adopted during the construction period, also include
coefficients and parameters adopted without any actual data on the site.
9
In order to obtain more accurate information, it would be desirable to install
a hydro-meteorological station in a section of the river that is representative
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
16
of the Project. Even if the works start soon, the information obtained will
always be useful and will allow future adjustment of the parameters
necessary for operation.
•
•
With respect to the studies conducted on the behavior of generation with
different dam heights and installed capacities, it was concluded that:
9
Energy production is marked by hydraulicity in the different months of the
year. In wet months (June to September), more power can be generated
and demand is covered.
9
In months with low hydraulicity, demand is only partially covered.
9
The above shows the reservoir’s poor regulation, considering that in wet
months or periods the surplus flows will be spilled.
9
As the reservoir level is increased (more regulation) or installed capacity is
reduced, the percentage of demand coverage grows for the same load
factor.
9
In the actual case, 140 MW at delivery point and maximum reservoir level
at 462.00 m.a.s.l., the trend is confirmed: even with smaller load factors,
there is a deficit in power generation in months with low hydraulicity.
The potential increase in dam height will have little influence on the installed
capacity due to the great existing fall, although it will improve annual power
generation, considering the greater regulation capacity and the following
features:
9
The increase in the maximum level from 462 to 468 m 5 represents an
increase of 26 % in the maximum height of Amaila Dam and 30 % in
Kuribrong Dam, with major economic implications.
9
In addition to more investment, other aspects linked to the larger flooded
area should be considered, in particular, associated environmental aspects.
9
Another alternative to enhance the dam’s regulation capacity, and therefore
its annual average energy, could be the implementation of circular sector
gates allowing some of the flows in wet months to be stored, thus reducing
spilling. (Source: own elaboration based on consultant’s experience and
consultant’s review of information on Amaila Falls).
9
It is considered, however, that this additional regulation capacity would be
limited and equal to approximately only 10% of the annual spilling (Source:
own elaboration based on consultant’s experience and consultant’s review of
information on Amaila Falls).
9
The convenience of installing gates to reduce the expected investment
remains to be considered (Source: own elaboration based on consultant’s
experience and consultant’s review of information on Amaila Falls).
Source: PPA multiscenario_Covermemo_20090820.pdf, prepared by MWH. It estimates
monthly energy generation for different scenarios.
5
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
17
8. MAIN CONCLUSIONS
•
Amaila Falls project brings structural benefits to the power system: a generation
mix hydro-thermal is better to hedge risks (oil prices volatility) than a system
that entirely relies on thermal plants.
•
Cost – benefit analysis evidences that the project is economically profitable.
The inclusion of Amaila Falls in GPL’s expansion plan reduces GPL’s net
present value of generation expenses throughout the study time horizon.
•
In other words, total benefits outweigh total costs.
•
It’s worth noting that Amaila Falls benefits are mainly concentrated in the
medium to long term, while PPA is evenly distributed during 20 years.
•
Assuming a WTI of 75 USD / bbl, an annual demand growth of 5 % in the
steady state (consistent with a GDP growth of 3.0 %) and the addition to the
grid of 131 GWh currently self generating (60 % in 2014 and 40 % in 2015), the
project’s economic indicators are the following:
NPV (kUSD) (@ 12%)
ERR
Benefit - Cost Ratio BCR
•
186,886
83%
0.70
If carbon credits are not considered in the project’s benefits, the above
economic indicators are the following:
NPV (kUSD) (@ 12%)
ERR
Benefit - Cost Ratio BCR
132,390
32%
0.66
•
GPL’s least alternative supply cost is the long run marginal cost (LRMC) of the
most competitive thermal technology available to expand its power system
(bunker-fired engines). Such LRMC is in between 13.0 and 14.0 ¢USD / kWh,
assuming a crude oil price (WTI) of 75 USD / bbl.
•
The inclusion of Amaila Falls in the capacity expansion plan at a fixed annual
payment of 105,000 k USD lowers net present value of GPL’s generation
expenses throughout the study time horizon, as demonstrated in the costbenefit analysis.
•
Competitiveness: The inclusion of Amaila Falls cuts down GPL’s average
supply costs to 11.5 ¢USD / kWh in the medium to long term.
•
In the short run, GPL’s average supply costs are higher than in the long term, in
the order of 12.6 ¢USD / kWh (effect of a take-or-pay contractual arrangement
and demand lower or close to energy delivered).
•
Market expansion by attracting industrial self generators back to the grid
mitigates this short run effect because the fixed annual payment is absorbed by
a larger demand.
•
Costs of self-generation (assuming a crude oil price of 75 USD / bbl) are
estimated between 15.8 and 20.7 ¢USD / kWh.
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
18
•
These figures represent the break-even price for an industrial customer
assessing the convenience of being supplied by the grid or self-generate,
assuming same reliability in supply options (GPL vs self generation).
•
The cost of self generate is larger than GPL’s average supply costs, both in the
short run (around 12.6 ¢USD / kWh) and in the medium-long term (11.5 ¢USD
/ kWh). The graph below illustrates these costs.
•
It’s worth noting that the above mentioned figures (cost of self generation vs
GPL’s average supply cost) are not strictly comparable. In fact, transmission
and distribution charges should be added to GPL’s average supply cost and
then compared to the cost of self-generate.
GPL's generating expenses and Costs of self generation
21.0
20.5
20.0
19.5
Prospective self generator
Total costs (includes capital expenditures)
19.0
18.5
18.0
17.5
in cUSD / kWh
17.0
16.5
Existing self generators
Variable costs
16.0
15.5
15.0
14.5
14.0
13.5
100 % Thermal Expansion
13.0
12.5
12.0
11.5
11.0
20
36
20
37
20
34
20
35
20
32
20
33
20
30
20
31
20
28
20
29
20
26
20
27
20
24
20
25
20
23
20
21
20
22
20
19
20
20
20
17
20
18
20
15
20
16
20
13
20
14
20
09
20
10
10.0
Expansion with Amaila as of Y 2014
Note: GPL's generating expenses
(T&D charges are not included)
20
11
20
12
10.5
•
Sensitivity to WTI: future scenarios of high crude oil prices contribute to
increase the competitiveness of Amaila Falls vis a vis the thermal expansion
(upside). Conversely, scenarios of low crude oil prices are a downside for the
project.
•
The following tables show the economic indicators of the cost-benefit analysis
for different scenarios of future crude oil prices, with and without considering
carbon credits as part of the total benefits):
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
19
Sensitivity to WTI (net cash flow includes carbon credits).-
Crude Oil price NPV (@ 12%)
Base Case (*)
Downside Cases
USD / bbl
75
70
65
60
55
k USD
186,886
145,052
103,217
61,383
19,549
ERR
BCR (**)
in %
83%
37%
23%
17%
13%
# of initial years with
negative cash flow
(cost > benefits)
0.70
0.67
0.64
0.61
0.58
1
2
4
6
8
(*) consistent with World Bank's latest projections
(**) Benefit - Cost ratio = NPV (Benefits) / NPV (Costs)
Time horizon: 40 years
Sensitivity to WTI (net cash flow does not include carbon credits).-
Crude Oil price NPV (@ 12%)
Base Case (*)
Downside
Cases
USD / bbl
75
70
65
60
55
k USD
132,390
90,556
48,721
6,887
-34,947
ERR
in %
32%
21%
16%
12%
10%
# of initial years with
negative cash flow
(cost > benefits)
BCR (**)
0.66
0.63
0.60
0.57
0.54
3
5
7
8
20
ERR stands for Economic Rate of Return
•
The number of initial years with negative cash flow (i.e. costs greater than
benefits) increase as WTI decreases, because direct savings in fuel costs are
reduced
•
Sensitivity to market expansion: In the short run, annual fixed payment for
Amaila’s output may outweigh the direct savings in operating costs and capital
expenditures in new thermal generators. Instead, in the medium to long run
benefits outweigh the costs.
•
Market expansion contributes to compensate the temporary imbalance between
total costs and total benefits.
•
The following table shows the project’s economic indicators for different
scenarios of market expansion:
Sensitivity to market expansion
Scenario
Base Case (*)
Upside Case
Self generators
switching to the grid
GWh-year
131 GWh (60 % in 2014
& 40 % in 2015)
NPV (@ 12%)
Economic rate
of return (ERR)
Benefit / Cost
ratio
k USD
in %
BCR
# of initial years with
negative cash flow
(costs larger than
benefits)
186,886
83%
0.70
195,664
positive cash flow
all years
0.71
105 GWh as of Y 2014
170,318
49%
0.69
2
79 GWh as of Y 2014
153,363
34%
0.68
3
100,870
19%
0.64
7
131 GWh as of Y 2014
1
zero
Downside Cases:
20% less than BC
40 % less than BC
Self generators decide not to switch to the grid
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
20
•
The number of initial years with negative cash flow (i.e. costs greater than
benefits) increases as market expansion decreases.
•
High supply costs in the short run might be mitigated considering efficient
contractual arrangements (fuel cost deduction during dry seasons, increasing
annuity over time, etc.)
•
Review on hydrology studies: The hydrology study done by MWH
encountered some difficulties due to lack of direct hydrological data at the
project site. Given the above mentioned constraint, MWH applied best practices
to process the available information.
•
Reservoir operation: Seasonal regulation and production of firm energy during
drier months is limited.
•
The optimization of the project design is limited because all available data has
been already considered. Design improvements would require additional
hydrological data collection.
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
21
SECTION I: FUNDAMENTALS OF THE ANALYSIS
1. INTRODUCTION
Guyana has substantial hydroelectric resources, but due to the complicated terrain and
the small size of the country the development of these resources has been delayed.
The developer, Synergy Holdings, performed an initial feasibility study undertaken by
Harza (MWH) in 2002 and advanced negotiations with GPL, the state-owned utility,
primary off-taker of Amaila energy production. However, the privatization of GPL and
later re-purchase by the Government delayed the development of the project. EPC
proposals were received Nov 2008, they include proposals from three Chinese
consortia, one Italian company and from one Indian-led consortium.
The Government of Guyana would potentially allow for this project to move forward
based on an acceptable yearly tariff.
Next steps include: to finalize discussions related to the PPA aspects, to continue
discussions with EPC contractors to reduce price and to adjust financial plans.
While the development of the 154 MW Amaila Falls projects is based on the decision to
shift from costly and imported fuel sources to using the abundant, domestic water
potential, the generation expansion plan has to consider developing the power sector in
the most economically efficient manner (i.e. least cost).
Amaila Falls hydro project is expected to cover a significant proportion of the existing
power demands in Guyana. As such, the characteristics of the Project must be
established in light of the existing and future power system (total installed capacity and
size of individual units, power system reliability and stability).
This Report provides a description of the economic fundamentals, assumptions and
results of the study conducted by Mercados Energéticos Consultores (ME) to achieve
the objectives of the Terms of Reference.
2. ECONOMIC RATIONALE
ME estimated the economic profitability of the project (on base case assumptions) and
performed a cost-benefit analysis, calculating the net present value of the project with a
benchmark discount rate of 12 %.
The study covered the following key aspects:
1. Electricity demand forecast over a twenty year period
Economic activity (GDP growth) was considered the main driver to explain demand
growth.
In addition, short run demand projections also contemplated other drivers to account
for demand growth (existing customers, new additions to customer base through
UAEP6, loss reduction, non-served energy associated to generation shortfall).
2. Least cost generation expansion plan
6
Unserved Areas Electrification Programme
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
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The optimal investment schedule to supply the forecasted load was modeled for two
different situations:
• a generation expansion plan fully based on thermal power plants and
• a generation expansion that includes Amaila Falls hydro project in Y 2014.
A comparison between both expansion plans was performed to assess costs and
benefits of Amaila Falls and to determine its economic rate of return:
• The cost of the project is basically the power purchase agreement (PPA)
between GPL and the developer that entitles the latter to receive a fixed annual
payment for the energy delivered.
• On the benefits side, the most important ones are GPL’s direct savings in fuel
purchases, in O&M costs and in capital expenditures in new thermal facilities. In
addition, the economic benefit of the reduction in green house gases emissions is
discussed.
Main assumptions for the optimal expansion plan are: crude oil prices scenario,
expected demand growth and type of technology available for candidate projects in
Guyana (in addition to Amaila Falls).
3. Competitiveness of Amaila Falls
ME compared GPL’s supply cost and cost of self generation to discuss the
competitiveness of the project in the short run.
In the medium to long term, assuming crude oil prices of 75 USD / bbl, GPL’s average
supply costs including Amaila Falls in its expansion plan are lower than the alternative
expansion option (diesel-fired generators).
4. Risk analysis (Sensitivity analysis)
Based on the cost benefit analysis developed for the Base Case, ME identified the
main factors that negatively influence the economic rationale of the project: namely fuel
prices and demand growth.
5. Review of existing studies (done by MWH) on the hydrology for the project
Existing studies on the hydrology and project design were reviewed in order to verify
the conclusions outlined by MWH and to assess possible design enhancements based
on available field data.
3. PROJECT BACKGROUND
3.1.
AMAILA FALLS PHYSICAL SETTING
The Amaila Falls Hydroelectric Project is located on the Kuribrong River in west central
Guyana, about 250 kilometers southwest of Georgetown. The dam site is at the
confluence of the Amaila and Kuribrong Rivers.
The Project would include a small storage reservoir created by two small dams
constructed at the confluence of the Amaila and Kuribrong Rivers, at the top of Amaila
Falls. The reservoir area is a heavily forested plateau with rock outcrops near the
surface. The river drops about 60 meters at the falls and then continues through a
series of rapids and smaller falls to the proposed powerhouse site.
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
23
Figure 1: Location Map
The Kuribrong River continues 90 kilometers downstream of the powerhouse site and
feeds into the Potaro River, which then flows about 30 kilometers to its confluence with
the Essequibo River. The Essequibo River crosses the coastal plain and drains to the
ocean about 35 kilometers northwest from Georgetown.
The Project would also include 296 kilometers of 230-kV, double-circuit transmission
line to connect the Project with potential customers.
3.2.
GUYANA POWER SECTOR OVERVIEW
The electricity sector in Guyana is dominated by Guyana Power and Light (GPL), a
vertically integrated government-owned utility with a monopolistic position on
transmission and distribution, and a major stake in generation.
GPL operates the Demerara and Berbice areas, where most of the country’s demand is
concentrated. It is expected that the completion of the Sophia – Onverwagt
transmission link by 2011 would realize the Demerara Berbice Interconnected System
(DBIS).
GPL owns and manages 142 MW of installed capacity (2009), all of which is based on
thermoelectric plants with diesel-engine driven generators. A considerable proportion of
GPL’s current power generation facilities are inefficient as the utility has resorted to the
use of both own and rented high-cost small independent generation units in order to
enhance generation capacity in some regions of the country.
Electrification in Guyana is low both in terms of access and in terms of intensity of use
relative to other countries in the region. Electrification is higher in coastal towns with a
high industry concentration, there are vast areas of the country underserved.
In fact, the Government of the Cooperative Republic of Guyana (GoG) has received
financing from the Inter-American Development Bank (IDB) towards the cost of the
Unserved Areas Electrification Programme (UAEP). The programme is jointly funded
by the IDB, the GoG and GPL. The key objectives are to provide electricity to at least
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
24
30,000 households in what are classified as Unserved Areas, and to assess and
reduce the distribution losses.
Electricity provision in Guyana is affected by its high reliance on expensive imported oil
and tariff-setting mechanisms (quarterly updated with fuel costs). Most of the installed
generation capacity in Guyana is based on diesel-engine driven generators, exposing
the sector to price shocks and the inherent volatility of the international oil markets.
The electricity sector in Guyana suffers major losses at both distribution and
commercialization activities, which are a major contributing factor to high tariffs. Losses
at the distribution level account for up to 33 % of the energy generated (Source: GPL).
At the commercial level, the utility is making efforts to enforce collection of bills, and to
eradicate theft. GPL is currently undertaking a loss reduction programme aiming at
reducing losses from its actual level to 20.7 % in a five year period (Source: GPL).
Electricity in Guyana is also generated by a limited number of Independent Power
Producers (IPPs, mainly sugar and mining companies). IPPs are mainly large
corporate firms that generate power for their own needs and sell excess capacity to the
national grid. Guysuco (Skeldon 30 MW co-generation facility) has started providing
energy to the grid 25 weeks per year. Energy deliveries to the grid were 39 GWh during
2009 and 81 GWh is estimated for Y 2010 (Source: GPL).
Deficiencies in power infrastructure and low reliability of service in Guyana may pose
an important constraint for the development of the country. The lack of reliable
infrastructure and services affect the development of the private sector by reducing its
competitiveness and discouraging additional private investment. The poor reliability of
electricity supply has placed a significant burden on companies in Guyana, which
reduces their competitiveness.
The development of physical infrastructure is critical for a sustainable economic growth
and improvement on quality of life.
According to the World Bank in its Guyana Investment Climate Assessment Report
(2007), four aspects of the investment climate were mentioned in the group of top
constraints: cost of financing, macroeconomic uncertainty, worker skills and education,
and electricity.
3.2.1.
SELF GENERATION
The poor reliability of supply generates important losses for companies through lost
revenues. The data from the World Bank (ICS 20077) indicated that while 100 % of
large firms participating in the survey have their own power generation, the proportion
of companies with such facilities along with the share of electricity generated internally
decreases significantly with the size of the industry. This fact has been confirmed in the
survey recently conducted among the most important self generators registered in the
Guyana Energy Agency (GEA) (see Annex I).
Key findings of the survey are:
• It confirmed that self-supply of electricity in Guyana meets a significant proportion
of the country’s electricity demand, although it is costly and generates economic
inefficiencies.
7
ICS stands for Investment Climate Survey conducted by the World Bank in Y 2007.
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
25
• The majority of the self generators are located along the East Bank of Demerara
corridor which is an area in close proximity with the existing GPL grid.
• The database of Guyana Energy Agency (GEA) contains about 622 entries.
• Approximately 40 self generators were surveyed. Most of them utilize their
generation equipment as load demand necessitates. A minority use them as
standby units.
• The results of the survey show that some 10.94 GWh is produced monthly by
individual self generators. This represents an annual generation of 131 GWh
(approximately 20 % of GPL’s gross demand).
• The results of the survey may be considered a lower limit for annual self
generation, given that only some of the data for the list of self generators has
been gathered.
3.2.2.
LINDEN AREA
Linden Power Company (LPC) is another major customer, as the planned transmission
line will be routed through Linden. Linden area is composed by a community of
approximately 6,000 inhabitants and a mining company (Bauxite company), with a total
consumption varying between 66 and 70 GWh-year, depending on the activity of the
mining company.
Presently, light diesel fuel is used for power generation in Linden.
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
26
SECTION II: DEMAND FORECAST
1. ELECTRICITY DEMAND DRIVERS
1.1.
MACROECONOMIC GROWTH
The main driver to account for electricity demand growth is the economic activity (GDP)
which explains the natural trend in demand growth.
Electricity demand in Guyana is closely related to its export activity, mainly primary
agricultural (sugar and rice) and mining (bauxite, gold) commodities. These exports
account for around two thirds of Guyana’s GDP and are the traditional economic
drivers. The manufacturing sector shows mixed performances and engineering and
construction recently expanded. Lately there has been an effort to diversify Guyana’s
productive base, especially in areas such as agriculture and the services sector.
Domestic output is highly dependent on commodity prices. Although it has expanded
for three consecutive years 2006, 2007 and 2008 (following growth rates of 5.1, 5.4
and 3.1 %, respectively), a slowdown is expected in 2009, mainly due to the decrease
in sugar prices (Source: Ministry of Finance, Guyana).
It’s worth noting that electricity generating capacity should be capable to flexibly
incorporate commodity market variance and for it, reserve margins should be widened
from current low levels.
1.2.
EXTRA-TENDENCY GROWTH IN THE SHORT RUN
Besides, in the short run, there are three factors that account for an extra tendency
growth of electricity sales within GPL’s serving area. These factors are added to the
projected electricity sales that result from the regression models as a function of GDP
in the first four years of the study time horizon:
• New connections under un-served areas electrification programmes and current
construction boom: 9,900 new connections under electrification projects and
10,000 new households in served areas in the next four years (2010 – 2013) at
an average specific consumption of 75 kWh per month per client. Source: GPL
• Reduction in non-served energy due to present generation shortfall: lost sales
due to power outages are estimated to be 1.3 % of total sales (4.9 GWh-year,
2009e). Source: GPL
• Loss reduction programme at the distribution level: the five-year programme
currently in place to replace defective meters and to reduce electricity theft is
expected to diminish system losses from its present level of 33 % to 20.7 %. The
expected cut down in technical and non technical losses per year is as follows
(Source GPL):
Year
Technical Losses
Non-technical Losses
2009
11.4 %
21.6 %
2010
10.6 %
19.4 %
2011
9.9 %
17.5 %
2012
9.3 %
15.7 %
2013
8.1 %
12.7 %
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
27
From Y 2013 onwards, losses remain constant at 20.8 %.
In addition, it is expected that a portion of the loss reduction will increase sales and a
portion will cut down demand, assuming a short run price elasticity of -0.2 (a 1 % price
increase results in a 0.2 % reduction in electricity consumption).
It’s worth mentioning that ME tested different econometric models to estimate the price
elasticity for residential, commercial and industrial sectors in Guyana. In all cases, tariff
was not a significant driver to explain demand evolution and econometric results were
not robust, mainly due to insufficient number of historical data points.
Therefore, ME adopted a benchmark approach to estimate price elasticity and
assumed that consumer behavior in Guyana is similar to other countries in the region.
Such benchmark analysis revealed that electricity demand is, in general terms, relative
inelastic to price changes: regression models in other countries of Latin America and
the Caribbean region8 give evidence of a price elasticity of -0.2 in the short run and
-0.5 in the long run.
2. REGRESSION MODELS
Conditioned to data availability, ME forecasted the electricity sales by type of customer
as a function of global GDP9. For each sector, ME tested different functional forms for
the regression models and selected those with the highest R-squared10 and the best
statistical indicators:
Type of customer
Independent variable
Functional form
Residential
Global GDP
Exponential
Commercial
Global GDP
Linear trend
Industrial
Global GDP
Exponential
Public Lightning
Linear trend with an autorregresive term
Regression parameters and statistical indicators are shown in the table below for each
consumption sector:
Dependent variable
Residential
consumption
LOG(C_RES)
Commercial
consumption
C_COM
Industrial
consumption
LOG(C_IND)
C_LP
Public lightning
8
Variable
LOG(GDP)
C
GDP
C
LOG(GDP)
C
TREND
CE_AP(-1)
C
Coefficient
1.425
-0.455
16.113
-33150.55
2.190
-7.360
429.919
0.487
-564.001
t-Statistic
6.739
-0.248
6.271
-2.213
12.961
-5.027
3.742
2.883
-1.692
Prob.
0.0001
0.809
0.0001
0.054
0
0.0007
0.0072
0.024
0.135
R-squared
0.835
0.814
0.949
0.977
Chile, Mexico, Panama, Costa Rica, Paraguay, Colombia and Dominican Republic
9
Source: Bureau of Statistics, 1988 constant prices
R squared is a statistical measure commonly used to express how well a regression line
approximates real data points.
10
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
28
Where:
LOG(C_RES): logarithm of residential customer’s consumption;
LOG(GDP): logarithm of GDP;
C: constant;
C_COM: commercial customer’s consumption;
LOG(C_IND): logarithm of industrial customer’s consumption;
C_PL: public lightning consumption;
C_PL(-1): public lightning consumption autorregresive term;
TREND: linear tendency term
Total demand elasticity to GDP growth is 1.75 (i.e. a 3.0 % GDP growth accounts for
5.2 % in demand growth). This elasticity varies among consumption sectors: 1.4 for
residential customers and 2.2 for industrial users.
It’s worth noting that the degree of confidence of econometric models increases with
the number of real data points included in the regression to estimate model’s
parameters. Guyana’s historical electricity sales series by type of customer are only
available since Y 2000 (Source: GPL), which is considered a relative short period of
time for a regression analysis, thus influencing the reliability of the results.
2.1.
FORECAST OF THE INDEPENDENT VARIABLE (GDP)
Once the econometric models were specified and its parameters estimated for each
sector, ME envisaged a base case macroeconomic scenario to forecast GDP growth
based on:
• IADB, WB and CEPAL forecasts in the short run (2009 – 2011).
• From Y 2011 onwards, ME defined a linear trend model with an autoregressive
term to forecast GDP:
Dependent Variable
LOG(GDP)
Variable
TREND
LOG(GDP(-1))
C
Coefficient
0.003
0.904
0.760
t-Statistic
3.026
15.764
1.607
Prob.
0.005
0.000
0.119
R-squared
0.948
Where:
LOG(GDP): logarithm of GDP;
TREND: linear tendency term;
LOG(GDP(-1)): logarithm of GDP autorregresive term;
C: constant
The projected GDP growth is shown in the table below:
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
29
Figure 2: Forecasted GDP growth
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
GDP at factor cost
G$M
Growth rate%
5360
5270
-1.7%
5426
3.0%
5352
-1.4%
5474
2.3%
5537
1.2%
5500
-0.7%
5587
1.6%
5478
-2.0%
5759
5.1%
6066
5.3%
2008
6253
Year
3.1%
2009
6393
2.2%
2010
6572
2.8%
2011
6803
3.5%
2012
6996
2.8%
2013
7197
2.9%
2014
7405
2.9%
2015
7621
2.9%
2016
7845
2.9%
2017 – 2025
3.0%
2026 onwards
3.1%
Sources: Bureau of Statistics & Ministry of Finance (historical figures), own elaboration based on CEPAL
and on World Bank projections (forecasted trend)
2.2.
ELECTRICITY DEMAND PROJECTION (GPL)
With the above mentioned assumptions related to economic growth and extra-tendency
factors in the short run, the forecasted total annual demand growth for GPL’s serving
area is shown in the graph and table below:
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
30
1600
15.0%
1400
12.0%
1200
9.0%
GWh - year
1000
6.0%
Total energy sales forecasted growth
800
3.0%
GDP expected growth
(independent variable)
Forecasted total energy sales in GWh-year
(with regression models
by consumption sector)
600
0.0%
400
-3.0%
200
-6.0%
0
Energy sales / GDP annual growth rate
Expected GDP growth and energy sales forecast
-9.0%
2000
2002
2004
2006
2008
2010
2012
2014
2016
2018
Year
Energy Sales: Historic Evolution (GWh-year)
GDP historic evolution (annual growth)
Energy sales: historic annual growth
2020
2022
2024
2026
2028
2030
2032
Energy sales forecast (GWh-year)
Forecasted GDP
Energy sales: forecasted growth
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
31
Year
2008
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
Residential
MWh
160364
174153
185080
188864
196551
204649
213122
222030
231378
241142
251414
262175
273448
285261
297585
310530
324069
338230
353045
368544
384723
401689
419444
437983
457386
477648
%
3.1%
8.6%
6.3%
2.0%
4.1%
4.1%
4.1%
4.2%
4.2%
4.2%
4.3%
4.3%
4.3%
4.3%
4.3%
4.4%
4.4%
4.4%
4.4%
4.4%
4.4%
4.4%
4.4%
4.4%
4.4%
4.4%
Commercial
MWh
64827
70401
74806
76399
79508
82744
86096
89574
93184
96902
100768
104758
108896
113176
117590
122164
126880
131752
136785
141983
147350
152905
158639
164540
170644
176941
%
-7.8%
8.6%
6.3%
2.1%
4.1%
4.1%
4.1%
4.0%
4.0%
4.0%
4.0%
4.0%
4.0%
3.9%
3.9%
3.9%
3.9%
3.8%
3.8%
3.8%
3.8%
3.8%
3.8%
3.7%
3.7%
3.7%
Industrial
MWh
130691
141928
150809
158035
168022
178776
190289
202658
215932
230097
245329
261644
279148
297907
317926
339418
362396
387039
413396
441590
471751
504113
538745
575757
615369
657768
%
4.6%
8.6%
6.3%
4.8%
6.3%
6.4%
6.4%
6.5%
6.6%
6.6%
6.6%
6.7%
6.7%
6.7%
6.7%
6.8%
6.8%
6.8%
6.8%
6.8%
6.8%
6.9%
6.9%
6.9%
6.9%
6.9%
Public Lighting
MWh
6269
6807
7233
7830
8634
9437
10241
11045
11849
12653
13456
14260
15064
15868
16673
17476
18280
19085
19888
20692
21497
22301
23103
23907
24711
25514
%
19.8%
8.6%
6.3%
8.2%
10.3%
9.3%
8.5%
7.9%
7.3%
6.8%
6.3%
6.0%
5.6%
5.3%
5.1%
4.8%
4.6%
4.4%
4.2%
4.0%
3.9%
3.7%
3.6%
3.5%
3.4%
3.3%
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
Annual consumption
MWh
362151
393290
417930
431128
452716
475607
499748
525307
552342
580793
610968
642837
676556
712212
749773
789588
831625
876106
923114
972808
1025319
1081007
1139931
1202187
1268110
1337871
%
1.7%
8.6%
6.3%
3.2%
5.0%
5.1%
5.1%
5.1%
5.1%
5.2%
5.2%
5.2%
5.2%
5.3%
5.3%
5.3%
5.3%
5.3%
5.4%
5.4%
5.4%
5.4%
5.5%
5.5%
5.5%
5.5%
New
connections
MWh
4478
4478
4478
Total Annual
Energy Sales
MWh
362151
393290
417930
435606
457193
480084
499748
525307
552342
580793
610968
642837
676556
712212
749773
789588
831625
876106
923114
972808
1025319
1081007
1139931
1202187
1268110
1337871
%
1.7%
8.6%
6.3%
4.2%
5.0%
5.0%
4.1%
5.1%
5.1%
5.2%
5.2%
5.2%
5.2%
5.3%
5.3%
5.3%
5.3%
5.3%
5.4%
5.4%
5.4%
5.4%
5.5%
5.5%
5.5%
5.5%
Technical
Losses
Non
Technical
Losses
%
11.4%
11.4%
10.6%
9.9%
9.3%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
%
21.6%
21.6%
19.4%
17.5%
15.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
Annual Demand
MWh
540524
587000
597042
619187
646935
673345
700924
736773
774691
814595
856917
901615
948908
998918
1051599
1107441
1166401
1228788
1294720
1364418
1438068
1516173
1598817
1686136
1778596
1876439
Growth rate %
8.60%
1.71%
3.71%
4.48%
4.08%
4.10%
5.11%
5.15%
5.15%
5.20%
5.22%
5.25%
5.27%
5.27%
5.31%
5.32%
5.35%
5.37%
5.38%
5.40%
5.43%
5.45%
5.46%
5.48%
5.50%
32
2.3.
ELECTRICITY DEMAND IN LINDEN AREA
As mentioned before, Linden Power Company (LPC) and Bauxite mining company are
another major customers, as the planned transmission line can easily be routed
through Linden. Linden area is composed by a community of approximately 6,000
inhabitants and the said mining company, with a total consumption varying between 66
and 70 GWh-year, depending on the activity of the mining company.
It is assumed that current 66.5 GWh-year (2009e, Source: LPC) will evolve with
macroeconomic growth (expected GDP).
2.4.
SELF-GENERATION
An independent consultant was engaged by National Investment and Commercial
Investments Ltd (NICIL) and the Guyana Power and Light Inc (GPL) to conduct a
survey to verify the level of self generation presently employed in Guyana, given the
fact that every person has the right to self generate. See Annex I for further details
(Survey Report).
The objective of the Survey was to:
• Conduct a field verification of the Self Generation database obtained from the
Office of the Prime Minister
• Update the said database
• Establish the level of Self Generation that is taking place.
The methodology used to execute the survey was to:
• Review the database supplied by the GEA (Guyana Energy Agency) with the
intention to identify the Top Twenty listed organizations.
• Conduct site visits to the various operations at which self generation is
predominant. That is mainly the so called “Top Twenty” industrial / commercial
organisations which are self generating.
• Conduct telephone interviews with other individuals and organisations listed in
the database to verify the accuracy of the data.
Main conclusions of the survey are the following
• The database of Guyana Energy Agency (GEA) contains about 622 entries.
• Approximately 40 self generators were surveyed. Most of them utilize their
generation equipment as load demand necessitates. A minority use them as
standby units.
• Monthly self generation estimated at 10.94 GWh, that represents more than 20 %
of GPL current demand.
• The results of the survey may be considered a lower limit for annual self
generation, given that only some of the data for the list of self generators has
been gathered.
• Self generation installed capacity is in excess of 47MW or 38 percent of GPL
installed capacity.
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
33
• Self generation is mostly used to secure reliable power supply
• All companies surveyed are within grid areas
• There are a number of firms which are interested in having GPL connections.
• There are two clear groups of operators with GPL connections. The first group
only use the GPL supply as a back up to their main source of supply and the
second group obtains all or nearly all of their supply from GPL.
• A number of firms will like to see the cost of power reduced and reliability and
quality improved.
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
34
SECTION III: COST-BENEFIT ANALYSIS FOR AMAILA FALLS
PROJECT
1. LEAST COST EXPANSION PLAN
While the development of the 154 MW Amaila Falls project is based on the decision to
shift from costly and imported fuel sources to using the abundant, domestic water
potential, the generation expansion plan has to consider developing the power sector in
the most economically efficient manner.
In order to estimate the economic profitability of Amaila Falls project, ME compared the
expansion of the power generation capacity of Guyana with and without Amaila Falls
project.
ME determined the type of technology available for candidate projects in Guyana in
addition to Amaila Falls project. For each technology selected, CAPEX and OPEX were
estimated according to market prices of new equipment, typical O&M costs for each
technology, efficiency and fuel price scenario.
The simulation model OPTGEN was applied to identify the optimal (least cost)
expansion plan for the power system in the long run. Two situations were considered:
1. Without Amaila Falls among the candidate projects: expansion of the generation
capacity fully based on thermal power plants, typically medium speed engines or
gas turbines, in both cases using liquid fuels (HFO, LFO) and
2. With Amaila Falls among the candidate projects: expansion of the generation
capacity assuming that Amaila Falls hydro project begins commercial operation in Y
2014. From then onwards, if new capacity additions are needed, they will be
thermal plants using liquid fuels.
The objective function is to minimize the expected supply costs, including investment,
operational costs and non-supplied energy cost; subject to an adequate reliability of the
system’s operation (reserve margin):
MIN TotalCosts[USD ] =
t = 40
∑ (CAPEX
t =1
t
+ OPEX t ) ∗ (1 + i ) −t
Subject to a reasonable level of non-supplied energy
Where
t
each year of the evaluation period (t =1: 2009)
CAPEX t [USD]:
Capital Expenses of each year t
OPEX t [USD]:
i:
Operational Expenses of each year t
Economic rate of return
The amount of un-served energy sets the quality standard. ME assumed a threshold of
1x10-3 of total demand (on average). New capacity additions are triggered in order to
keep this quality standard.
The simulation results for each alternative compute:
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
35
• New capacity additions (size, time) and expected CAPEX
• Expected dispatch of power plants and associated OPEX (fuel cost and O&M).
• Generation reserve margin
• Non-supplied energy
• Supply costs
The results attained for each capacity expansion situation are next compared to
estimate the measurable benefits of Amaila Falls project:
• Direct savings in fuel purchases for generation purposes
• Direct savings in O&M of the thermal generation fleet
• Direct savings in capital expenditures on new thermal facilities.
• Carbon emissions reduction
2. KEY ASSUMPTIONS
2.1.
DEMAND FORECAST
It was already discussed in Section II of this Report. The following table summarizes
the expected demand:
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
36
Period 2009 - 2021
Demand Forecast
GDP growth
Total Sales GPL system
T & D losses
Year
%
2009
2.2%
2010
2.8%
2011
2.8%
2012
2.8%
2013
2.9%
2014
2.9%
2015
2.9%
2016
2.9%
2017
3.0%
2018
3.0%
2019
3.0%
2020
3.0%
2021
3.0%
GWh
annual growth
393
418
6.3%
431
3.2%
453
5.0%
476
5.1%
500
5.1%
525
5.1%
552
5.1%
581
5.2%
611
5.2%
643
5.2%
677
5.2%
712
5.3%
in %
Technical
11.4%
10.6%
9.9%
9.3%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
Non-technical
21.6%
19.4%
17.5%
15.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
587
597
1.7%
619
3.7%
647
4.5%
673
4.1%
701
4.1%
737
5.1%
775
5.1%
815
5.2%
857
5.2%
902
5.2%
949
5.2%
999
5.3%
66
68
2.8%
70
2.8%
72
2.8%
74
2.9%
76
2.9%
79
2.9%
81
2.9%
83
3.0%
86
3.0%
88
3.0%
91
3.0%
94
3.0%
0.60
79
0.40
131
135
2.9%
139
3.0%
143
3.0%
148
3.0%
152
3.0%
157
3.0%
856
14.5%
947
10.6%
991
4.7%
1,037
4.7%
1,086
4.7%
1,138
4.7%
1,192
4.8%
1,249
4.8%
Gross generation GPL system
GWh
annual growth
Linden Power Company
GWh
Self generation switching to the grid
GWh
Total expected demand
Expected demand growth
GWh
%
653
665
1.8%
689
3.6%
719
4.3%
748
4.0%
MW
MW
75
108
76
110
79
114
82
119
85
124
Average load
Peak demand
-
-
-
-
-
98
142
108
157
113
164
118
172
124
180
130
188
136
197
143
207
Period 2022 – 2053 (selected years)
Demand Forecast
GDP growth
Total Sales GPL system
T & D losses
Year
%
2022
3.0%
2023
3.0%
2024
3.0%
2025
3.0%
2030
3.1%
2035
3.1%
2040
3.1%
2045
3.1%
2050
3.1%
2053
3.1%
GWh
annual growth
750
5.3%
790
5.3%
832
5.3%
876
5.3%
1,140
5.5%
1,479
5.1%
1,901
5.1%
2,443
5.1%
3,140
5.1%
3,650
5.1%
in %
Technical
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
GWh
annual growth
1,052
5.3%
1,107
5.3%
1,166
5.3%
1,229
5.3%
1,599
5.5%
2,073
5.1%
2,659
5.1%
3,412
5.1%
4,379
5.1%
5,086
5.1%
Linden Power Company
GWh
97
3.0%
100
3.0%
103
3.0%
106
3.0%
123
3.1%
143
2.9%
164
2.9%
190
2.9%
219
2.9%
238
2.9%
Self generation switching to the grid
GWh
161
3.0%
166
3.0%
171
3.0%
176
3.0%
205
3.1%
239
3.1%
278
3.1%
324
3.1%
377
3.1%
413
3.1%
Total expected demand
Expected demand growth
GWh
%
1,310
4.8%
1,373
4.9%
1,440
4.9%
1,511
4.9%
1,927
5.0%
2,454
4.8%
3,102
4.8%
3,926
4.8%
4,975
4.9%
5,737
4.9%
Non-technical
Gross generation GPL system
Average load
Peak demand
MW
MW
149
217
157
227
164
238
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
172
250
220
319
280
406
354
513
448
649
568
823
655
949
37
2.2.
FUEL PRICES
The variable cost of production of thermal power plants is largely based on the cost of
fuel and plant’s efficiency and, in second place, on the operation and maintenance
costs. In turn, the cost of fuel depends on crude oil price (WTI). LFO has historically
been more expensive than HFO, as shown in the graph below (evolution of
international prices of HFO (fuel oil #6), LFO (fuel oil # 2) and crude oil (WTI), 1998 –
Aug 2009).
WTI, HFO & LFO
Historic Evolution 1998 - Aug 2009
Source of data: Energy Information Administration (www.eia.doe.gov)
170,0
160,0
150,0
140,0
130,0
120,0
USD / bbl
110,0
100,0
90,0
80,0
70,0
60,0
50,0
40,0
30,0
20,0
10,0
D
ic
-9
Ab 7
r-9
Ag 8
o9
D 8
ic
-9
Ab 8
rAg 99
o9
D 9
ic
-9
Ab 9
rAg 00
o0
D 0
ic
-0
Ab 0
rAg 01
o0
D 1
ic
-0
Ab 1
rAg 02
o0
D 2
ic
-0
Ab 2
rAg 03
o0
D 3
ic
-0
Ab 3
rAg 04
o0
D 4
ic
-0
Ab 4
rAg 05
o0
D 5
ic
-0
Ab 5
rAg 06
o0
D 6
ic
-0
Ab 6
rAg 07
o0
D 7
ic
-0
Ab 7
rAg 08
o0
D 8
ic
-0
Ab 8
rAg 09
o09
-
Month - Year
EIA - FO 6
EIA - Diesel Oil (FO 2)
WTI
Therefore, ME forecasted the future international prices for liquid fuels as a linear
function of crude oil prices, with the following regression parameters:
HFO (in USD / bbl, FOB) = +1.684 + 0.726 x Crude Oil Price (USD / bbl)
LFO (in USD / bbl, FOB) = -3.556 + 1.269 x Crude Oil Price (USD / bbl)
Foreign freight and insurance is added to the forecasted international prices (5.8 USD /
bbl).
For the Base Case, ME adopted a crude oil price of 75 USD / bbl, consistent with the
latest projections (June 2009) of the World Bank.
The table shows the forecasted fuel prices:
Crude Oil
(USD / bbl)
FOB
Freight
CIF
FOB
Freight
CIF
75
56.1
5.8
61.9
91.6
5.8
97.4
2.3.
HFO (USD / bbl)
LFO (USD / bbl)
TYPE OF TECHNOLOGY TO EXPAND THE POWER SYSTEM
Forecasts of electricity supply costs generally assume that, in the long run, the market
will be in equilibrium and the long run marginal cost of the system will reflect the cost of
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
38
supplying an additional unit of energy with the most competitive available technology
for such market (i.e. at minimum cost).
Subject to fuel availability, the most significant factors influencing costs include fixed
capital costs, variable operating costs (fuel and O&M costs) and the financial structure
(discount rate). It also depends on the expected load factor of the new entry
technology.
Although the most common expansion technology adopted in Guyana in recent years
has been bunker-fired internal combustion engines, it was necessary to verify, given
the assumed evolution of fuel prices in the future, if this was the most competitive
expansion technology in the long run.
The most competitive expansion technology is defined as the one that minimizes the
long run marginal cost of the system, i.e. the total cost (CAPEX and OPEX) to satisfy
an additional unit of demand.
Based on fuel availability in Guyana, ME selected two alternative technologies to
estimate the long run marginal cost of Guyana’s power system:
• HFO medium speed engines
• Gas turbines using LFO
For each technology selected as potential candidate to expand the generating capacity,
ME estimated its CAPEX and OPEX according to market prices of new equipment,
typical O&M costs for each technology, efficiency and fuel prices scenario.
In both cases, ME selected a 7 MW capacity power unit, that is considered suitable for
the demand size and annual growth of Guyana Power System.
To compute capital expenditures (CAPEX) in thermal power units, it is assumed that
they will be developed as private sector projects. Thus, it was assumed the private
investor will expect a rate of return on equity of 16.07 % (which was estimated using
the WACC method).
The main characteristics adopted for each technology to compute the long run marginal
cost (LRMC) are shown in the table below:
Parameter
HFO medium speed engines
Gas turbines using LFO
Investment Cost
1,100 USD / kW
450 USD / kW
Return on equity
16.07 %
16.07 %
Repayment period
10 years
10 years
O&M
0.9 ¢USD / kWh
0.45 ¢USD / kWh
Type of fuel
Heavy fuel oil
Light fuel oil
Fuel cost on site
61.9 USD / bbl
97.4 USD / bbl
Gross capacity
7 MW
7 MW
40 %
44 %
2,158.9 kCal / kWh
1,932 kCal / kWh
56.4 Gal / MWh
55 Gal / MWh
70 %
70 %
Heat rate
Expected dispatch
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
39
The optimal technology for the new capacity additions is the one that satisfies the leastcost principle. HFO medium speed engines is the favored expansion technology for
relative high dispatch factors (see graph below). The long run marginal cost (includes
CAPEX and OPEX) for this technology is around 13.0 – 14.0 ¢USD / kWh, assuming a
crude oil price of 75 USD / bbl.
Long run marginal cost of thermal expansion
HFO-fired combustion engines vs LFO-fired gas turbines
28.0
in cUSD / kWh
26.0
24.0
22.0
20.0
18.0
16.0
14.0
12.0
0%
20%
40%
60%
80%
100%
120%
Dispatch factor
Engine
Gas turbine
The competitiveness of HFO engines increases when crude oil prices increase,
(because the spread between HFO and LFO prices also raises).
2.4.
COSTS OF AMAILA FALLS PROJECT
The cost breakdown of the project was taken from Sithe’s financial model and it
constitutes an input for ME’s cost-benefit analysis:
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
40
CAPITAL COST ASSUMPTIONS
EPC
EPC
479,000
479,000
Repayment of Bridge loan
Spare Parts / Startup
Insurance
Development Company Expenses, Manag
Operator Labor
Admin. Expenses
Developers
Bank's Legal Counsel
Legal Counsel
Owner's Engineer
Lender's Engineer
O&M Training
Working Capital
Debt Service Reserve
7,234
5,000
12,000
3,071
2,245
12,000
2,000
3,000
6,000
3,000
1,500
1,673
43,206
CAPEX Before Financing Fees & IDC
580,929
Interest During Construction
Commitment Fee
Upfront + Appraisal Fee
Development Fee to Sithe
Capital Costs incl tranche 1a
Transmission Line and Substations
Interest During Construction 1b
Commitment Fee 1b
Upfront + Appraisal Fee 1b
42,243
5,408
7,331
13,032
648,943
0
2,678
0
0
Operating Expenses:
Fixed O&M Local:
Labor
Bank Fees
Chemicals
Environmental
Occupational safety
Spare Parts
Utilities and Other Operating
Routine equipment maintenance
Scheduled maintenance
Equipment mods & replacements
Business Insurance
G&A Expenses
Fixed O&M US:
Routine equipment maintenance
Labor
Scheduled Maintenance
Equipment mods & replacements
Other
Other
Other
Other
Other
Total Fixed O&M:
Variable O&M:
Chemical and Non-Fuel Consumables
Water
Utilities and Other Operating
Equipment Maintenance (excluding LTSA)
Maintenance Reserve
Transmission Tariff (TUST + TUSD)
O&M Costs
Equity Insurance
Total Variable O&M:
Total O&M Expense:
$
$
$
$
$
$
$
$
$
$
$
$
755
75
3
109
94
196
91
91
62
21
2,000
1,089
$
$
$
$
$
823
149
559
190
0
0
0
0
$6,307
$/MWh
$0
0
0
0
0
0.00
0.00
% of Equity
1.5%
$6,307
651,621
As indicated by the Client, the power purchase agreement between GPL and the
developer will consist of a fixed annual payment of 105,000 k USD.
3. LEAST COST EXPANSION PLAN
As already mentioned in previous sections, in order to estimate the economic
profitability of Amaila Falls project, ME compared the expansion of Guyana’s power
generation capacity with and without Amaila Falls project and estimated the benefits of
the hydro project as the sum of:
• Direct savings in fuel purchases,
• Direct savings in O&M costs and
• Direct savings in capital expenditures (in new thermal facilities).
Carbon emission reduction was also estimated as part of total project’s benefits,
assuming a CER of 10.4 USD / ton CO2 (Source: Pointcarbon).
However, it’s worth noting that, in principle, Amaila Falls would not be elegible to earn
carbon credits because its size exceeds 20 MW. However, UN is currently reviewing
the elegibility conditions for hydropower plants to include larger plants as long as
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
41
environment and local communities are preserved.
The optimal (least cost) investment schedule to supply the forecasted load was
modeled for two different situations:
1. Generation capacity expansion fully based on thermal power plants (selected
technology was bunker-fired medium speed engines) and
2. Generation capacity expansion considering that Amaila Falls hydro project
begins its commercial operation in Y 2014. From then onwards, the selected
expansion technology, if needed, is bunker-fired engine.
The model results for each alternative include: new capacity additions (size, time) and
expected CAPEX, expected dispatch of power plants and associated OPEX (fuel cost
and O&M) and generation reserve margin.
3.1.
NEW GENERATING CAPACITY
The size and timing of the new capacity additions necessary to meet the forecasted
load subject to a given quality threshold11 are shown in the graphs below, for each
expansion modeled:
Guyana: Supply & Demand Balance
Generation Capacity Expansion: Option # 1 (100 % Thermal)
130%
680
640
120%
600
21
560
28
21
440
in MW
360
320
280
240
200
120
21
90%
28
400
160
100%
28
480
21
- 34%
32%
-
14
7
7
14
14
14
14
14
21
14
80%
21
70%
60%
50%
40%
30%
42
7 -
26%
23%
23%
22%
19%
80
7
14
14
21
21
28%
28%
26%
26%
29%
28%
27%
Cumulative New Thermal Adds (y - 1)
Annual New Thermal Additions
Reserve Margin
2037
2036
2035
2034
2033
2032
2031
2030
2029
2028
2027
2026
2025
2024
2023
2022
2021
2020
2019
2018
2017
2016
2015
0%
2014
2012
2011
2010
2009
2013
7%
Existing Thermal
20%
10%
40
-
Reserve margin in %
520
110%
Peak Demand
It’s worth noting that capacity additions meet the expected demand growth, while
keeping the system’s reliability (reserve margin). The resulting reserve margin
(Installed Capacity / Peak Demand) is approximately 30 %.
11
unserved demand less than 1 x 10–3 of total demand
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
42
Guyana: Supply & Demand Balance
Generation Capacity Expansion: Option #2 Amaila Falls begins operations in Y 2014
130%
680
640
120%
600
21
560
28
21
92%
440
in MW
360
74%
320
66%
280
-
-
-
59%
-
240
90%
-
-
-
-
14
14
14
21
14
21
21
14
80%
21
70%
60%
50%
52%
40%
45%
200
120
21
28
400
160
100%
28
480
- 34%
32%
38%
7 -
30%
32%
28%
28%
26%
26%
22%
19%
80
29%
28%
27%
2037
2036
2035
2034
2033
2032
2031
2030
2029
2028
2027
2026
2025
2024
2023
2022
2021
2020
2019
2018
2017
2016
2015
0%
2014
2012
2011
2010
2013
7%
2009
20%
10%
40
-
Reserve margin in %
520
110%
Amaila Falls (@delivery point)
Existing Thermal
Cumulative New Thermal Adds (y - 1)
Annual New Thermal Additions
Reserve Margin
Peak Demand
As can be seen in the graph, the addition of Amaila Falls by Y 2014 introduces a
(temporary) excess of installed capacity. Reserve margin peaks and gradually
decreases until Y 2022 when it falls below the target value and new thermal generation
capacity is added to the system. In the long run there exist no differences in annual
capacity additions between both expansion options.
3.2.
EXPECTED DISPATCH OF POWER PLANTS
The following graphs show the expected dispatch of power plants for each expansion
option analyzed (see Annex I Model’s output (generation balance):
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
43
2,900
2,800
2,700
2,600
2,500
2,400
2,300
2,200
2,100
2,000
1,900
1,800
1,700
1,600
1,500
1,400
1,300
1,200
1,100
1,000
900
800
700
600
500
400
300
200
100
-
Expected dispatch of new thermal facilities
Expected Guysuco energy deliveries to the grid
20
37
20
36
20
34
20
35
20
32
20
33
20
31
20
29
20
30
20
27
20
28
20
26
20
25
20
23
20
24
20
21
20
22
20
20
20
18
20
19
20
16
20
17
20
14
20
15
20
09
20
12
20
13
Expected dispatch of existing thermal facilities
20
10
20
11
GWh per year
Guyana Power System Expected Dispatch of Power Plants Option #1 Thermal expansion
Expected dispatch of new thermal facilities
Guysuco energy deliveries to the grid
20
36
20
37
20
34
20
35
20
33
20
31
20
32
20
29
20
30
20
28
20
27
20
25
20
26
20
23
20
24
20
22
20
20
20
21
20
18
20
19
Amaila Mean Energy Production
20
16
20
17
20
14
20
15
20
12
20
13
Expected dispatch of
existing thermal facilities
20
11
2900
2800
2700
2600
2500
2400
2300
2200
2100
2000
1900
1800
1700
1600
1500
1400
1300
1200
1100
1000
900
800
700
600
500
400
300
200
100
0
20
09
20
10
GWh per year
Guyana Power System Expected Dispatch of Power Plants Option #2 with Amaila
Amaila Falls’s energy production is expected to meet base load, thermal units will be
dispatched as needed to meet peak demand.
It should be mentioned that, although Amaila Falls’s mean energy production may be
higher than expected demand in the early years of the project, Amaila’s energy output
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
44
is subject, by definition, to hydro volalitility. Thus, there are some months of the year
(during the dry season) when thermal plants need to be dispatched to meet the portion
of demand load that can not be met by Amaila’s production. This is the reason why
thermal dispatch is not null even in the time period when Amaila’s mean energy
production is larger than expected demand.
Amaila’s expected average energy production (983 GWh) is well-matched with
expected demand growth driven by existing GPL / Linden customers; and the addition
of 131 GWh-year of self generation as of 2014.
As of Y 2022 increasing amounts of thermal generation are needed, on top of Amaila
mean energy production, to meet expected demand and to keep a reasonable reserve
margin in the system.
4. COST-BENEFIT ANALYSIS
4.1.
COST STREAM
Based on Sithe’s financial model, ME assumed a fixed annual payment for Amaila Falls
energy production of 105,000 k USD during 20 years, regardless the amount of energy
delivered and / or taken by the off-takers.
4.2.
BENEFIT STREAM
Once determined the necessary new capacity additions to meet expected load, total
supply costs (CAPEX and OPEX) for each expansion option were estimated.
The economic benefits of the project were identified and measured, by category, over
the study time horizon (40 years):
• Direct savings in fuel consumption
• Direct savings in O&M costs of thermal facilities
• Direct savings in capital expenditures in new thermal units.
• Carbon emissions reduction
The benefit stream was then computed as the sum of the four categories recognized.
4.2.1.
DIRECT SAVINGS IN FUEL CONSUMPTION
In estimating the avoided costs in fuel consumption, it has been assumed the following
parameters:
Average efficiency existing generation fleet:
34 %
Average efficiency new thermal facilities:
40 %
Fuel costs:
HFO:
61.9 USD / bbl on site
LFO
97.4 USD / bbl on site
Generation mix progresses from its current 70 / 30 HFO / LFO towards 100 % HFO.
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
45
Amaila Falls would significantly reduce the imports of liquid fuels for generation
purposes. Avoided costs in fuel consumption for generation purposes are in the range
of 80,000 to 85,000 thousand dollars per year. These direct savings represent
approximately 68 % of total economic benefits considered. The following graph shows
fuel costs with and without Amaila Falls hydro project:
Fuel Costs with Amaila vs Thermal Expansion
225,000
200,000
175,000
k USD
150,000
125,000
100,000
75,000
50,000
25,000
Fuel Costs - 100 % Thermal Expansion
4.2.2.
2037
2035
2036
2033
2034
2031
2032
2029
2030
2027
2028
2025
2026
2023
2024
2021
2022
2019
2020
2017
2018
2015
2016
2013
2014
2011
2012
2009
2010
-
Fuel Costs with Amaila Falls
DIRECT SAVINGS IN O&M OF THERMAL GENERATION FLEET
In estimating the avoided costs in 0&M expenses, it has been assumed the following
parameters:
O&M thermal facilities (includes lube consumption):
0.9 ¢USD / kWh
O&M, Insurance hydro plant (source: financial model):
0.6 ¢USD / kWh
Direct savings in O&M costs are in the range of 2,300 to 2,500 thousand USD per year,
representing around 2 % of total economic benefits identified.
4.2.3.
DIRECT SAVINGS IN CAPITAL EXPENDITURES IN NEW THERMAL FACILITIES
In estimating the direct savings in capital expenditures in new thermal generators, it
has been assumed the following parameters:
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
46
Capacity
7 MW
Investment cost
1,100 USD / kW
Return on equity
16.07 %
Repayment period
10 years
Efficiency
40 %
Expected dispatch
0.6 – 0.7
Direct savings in annual payments for new thermal facilities are approximately 30,000
thousand dollars per year, accounting for 24 % of total economic benefits.
4.2.4.
CARBON EMISSIONS REDUCTION
Finally, to estimate the carbon emissions reduction the following parameters were
considered:
Fuel option - Emission Factor
CER
kg CO2 / kg
diesel
USD / ton CO2
3.07
10.4
Source: Pointcarbon
Benefits from carbon credits are estimated in 6,600 thousand dollars per year (approx.
5 % of total benefits identified).
As already mentioned, it’s worth noting that, in principle, Amaila Falls would not be
elegible to earn carbon credits because its size exceeds 20 MW. However, UN is
currently reviewing the elegibility conditions for hydropower plants to include larger
plants, as long as environment and local communities are preserved. Moreover,
Denmark has recently approved a 81 MW Chinese hydro project as CDM, awaiting to
obtain carbon credits. The project will now seek for UN’s approval (Source:
PointCarbon).
4.3.
COSTS AND BENEFITS STREAM
Amaila’s fixed costs are evenly distributed over 20 years (PPA is a fixed annual
payment of 105,000 k USD) while Amaila’s benefits are mainly concentrated on
medium to long term (this is variable and depends on expected market development
and oil prices).
Amaila project brings structural benefits to the power system: a generation mix hydro –
thermal is better to hedge risks (oil prices volatility) than a system that entirely relies on
thermal plants.
Cost-benefit stream is shown in the graph below:
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
47
Amaila Falls Project: Costs and Benefits Stream
160,000
Savings in O&M costs
Carbon credits
140,000
120,000
Savings in CAPEX (thermal units)
80,000
60,000
Savings in liquid fuel costs
40,000
20,000
2037
2036
2035
2034
2033
2032
2031
2030
2029
2028
2027
2026
2025
2024
2023
2022
2021
2020
2019
2018
2017
2016
-20,000
2015
2014
in thousand US dollars per year
100,000
-40,000
Fixed annual payment (PPA):
-105,000 k USD
-60,000
-80,000
-100,000
-120,000
Savings in Fuel Costs
4.4.
Savings in CAPEX annual payments
Savings in O&M Expenses
Carbon Credits
Total Costs
NET PRESENT VALUE OF THE PROJECT AND ECONOMIC RATE OF RETURN
Based on the costs and benefits identified, ME computed the net present value of the
project, using the benchmark discount rate of 12 %.
Under the set of assumptions and economic fundamentals described along this
document, the economic indicators of the project are the following:
NPV (kUSD) (@ 12%)
ERR
Benefit - Cost Ratio BCR
186,886
83%
0.70
BCR= NPV (Benefits) / NPV (Costs)
ERR=Economic Rate of Return
The annual net cash flow of the project (Costs – Benefits) is shown below:
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
48
Net Cash Flow (Benefits minus Costs)
27,500
25,000
22,500
in thousand US dollars per year
20,000
17,500
15,000
12,500
10,000
7,500
5,000
2,500
2033
2032
2031
2030
2029
2028
2027
2026
2025
2024
2023
2022
2021
2020
2019
2018
2017
2016
2015
-2,500
2014
-
-5,000
-7,500
Cash Flow
GPL’s generation expenses in the first year of the time horizon are higher with Amaila
than without Amaila. The rest of the years benefits outweigh costs.
The cost differential in the first year is reduced if one assumes a more aggressive
market expansion (self generation, Linden) and / or higher crude oil prices than
considered in the Base Case (See Section V Sensitivity Analysis).
The following table shows the costs and benefits stream 2009 – 2053.
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
49
Period 2009 - 2017
COST-BENEFIT ANALYSIS FOR AMAILA FALLS PROJECT
MAIN ASSUMPTIONS
Crude Oil Price (WTI)
Demand Forecast
GDP growth
Total Sales GPL system
T & D losses
Year
USD / bbl
2009
75
2010
75
2011
75
2012
75
2013
75
2014
75
2015
75
2016
75
2017
75
Year
%
2009
2.2%
2010
2.8%
2011
2.8%
2012
2.8%
2013
2.9%
2014
2.9%
2015
2.9%
2016
2.9%
2017
3.0%
GWh
annual growth
393
418
6.3%
431
3.2%
453
5.0%
476
5.1%
500
5.1%
525
5.1%
552
5.1%
581
5.2%
in %
Technical
11.4%
10.6%
9.9%
9.3%
8.1%
8.1%
8.1%
8.1%
8.1%
Non-technical
21.6%
19.4%
17.5%
15.7%
12.7%
12.7%
12.7%
12.7%
12.7%
Gross generation GPL system
GWh
annual growth
587
597
1.7%
619
3.7%
647
4.5%
673
4.1%
701
4.1%
737
5.1%
775
5.1%
815
5.2%
Linden Power Company
GWh
66
68
2.8%
70
2.8%
72
2.8%
74
2.9%
76
2.9%
79
2.9%
81
2.9%
83
3.0%
Self generation switching to the grid
GWh
0.60
79
0.40
131
135
2.9%
139
3.0%
Total expected demand
Expected demand growth
GWh
%
653
665
1.8%
689
3.6%
719
4.3%
748
4.0%
856
14.5%
947
10.6%
991
4.7%
1,037
4.7%
MW
MW
75
108
76
110
79
114
82
119
85
124
Average load
Peak demand
-
-
-
-
-
98
142
108
157
113
164
118
172
-105,000
-105,000
-105,000
-105,000
AMAILA FALLS COSTS
PPA (fixed annual payment)
k USD
ECONOMIC BENEFITS
Savings in Operating Costs
Fuel Consumption
Prices
HFO (includes freight)
LFO (includes freight)
Generation mix
Year
2009
2010
2011
2012
2013
2014
2015
2016
2017
USD / bbl
USD / bbl
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
61%
39%
70%
30%
70%
30%
80%
20%
82%
18%
83%
18%
85%
15%
86%
14%
86%
14%
HFO
LFO
Expansion Plan without Amaila
Expansion Plan with Amaila Y 2014
Savings in Fuel Costs
O&M Expenses
O&M unit costs thermal engines
O&M Amaila Falls
bbl
k USD
bbl
k USD
980,214
932,207
970,598
1,008,652
1,054,088
1,170,802
1,287,132
1,348,058
1,403,107
75,331
67,657
70,443
68,231
70,265
77,756
83,755
87,022
90,427
k USD
USD / MWh
USD / MWh
980,214
932,207
970,598
1,008,652
1,054,088
-
5,650
50,893
86,206
75,331
67,657
70,443
68,231
70,265
-
368
3,285
5,556
-
-
-
-
-
77,756
83,387
83,737
84,872
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
Expansion Plan without Amaila
Expansion Plan with Amaila Y 2014
k USD
k USD
5,530
5,530
5,259
5,259
5,476
5,476
5,744
5,744
6,000
6,000
6,976
5,219
7,792
5,566
8,188
5,935
8,605
6,300
PPA Guysuco
Expansion Plan without Amaila
Expansion Plan with Amaila Y 2014
k USD
k USD
4,337
4,337
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
4,760
9,007
9,007
9,007
9,007
9,007
9,007
Savings in O&M Expenses
k USD
Total Savings in Operating Costs
Savings in Capital Expenditures
in Thermal Plants
Year
Investment Cost
USD / kW
%
Return on capital (assumes private inve
Repayment period
years
Module
MW
New thermal capacity additions per year
Expansion Plan without Amaila
Expansion Plan with Amaila Y 2014
Expansion Plan without Amaila
Expansion Plan with Amaila Y 2014
Fuel option - Emission Factor
Carbon bonds price
Reduction in Fuel Consumption
Reduction in CO2
tonnes
tonnes
GHG Emissions Reduction
k USD
TOTAL ECONOMIC BENEFITS
NET CASH FLOW
-
-
-
6,005
2,226
2,253
2,305
-
-
-
83,761
85,613
85,990
87,176
2009
2010
2011
2012
2013
MW-year
MW-year
-
-
-
7
7
k USD
k USD
-
-
-
1,597
1,597
Year
kg CO2 /
kg diesel
USD / t
-
2014
2015
42
-
21
-
1,597
1,597
11,181
1,597
9,584
2016
2017
1,100
16%
10
7
Savings in CAPEX annual payments
GHG Emissions Reduction
-
-
-
-
-
-
-
2009
2010
2011
2012
2013
2014
7
14
-
15,973
1,597
17,570
1,597
20,765
1,597
14,376
15,973
19,168
2015
-
2016
2017
3.07
10.43
k USD
-
-
-
-0
-0
-0
-0
180,123
552,979
-
-
-
-0
-0
5,768
6,313
6,390
6,487
-
-
-
-0
-0
99,112
106,302
108,353
112,831
-5,888
1,302
3,353
7,831
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
197,151
605,254
199,564
612,661
202,600
621,983
50
Period 2018 - 2026
COST-BENEFIT ANALYSIS FOR AMAILA FALLS PROJECT
MAIN ASSUMPTIONS
Crude Oil Price (WTI)
Demand Forecast
GDP growth
Total Sales GPL system
T & D losses
Year
USD / bbl
2018
75
2019
75
2020
75
2021
75
2022
75
2023
75
2024
75
2025
75
2026
75
Year
%
2018
3.0%
2019
3.0%
2020
3.0%
2021
3.0%
2022
3.0%
2023
3.0%
2024
3.0%
2025
3.0%
2026
3.1%
GWh
annual growth
611
5.2%
643
5.2%
677
5.2%
712
5.3%
750
5.3%
790
5.3%
832
5.3%
876
5.3%
923
5.4%
in %
Technical
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
GWh
annual growth
857
5.2%
902
5.2%
949
5.2%
999
5.3%
1,052
5.3%
1,107
5.3%
1,166
5.3%
1,229
5.3%
1,295
5.4%
Linden Power Company
GWh
86
3.0%
88
3.0%
91
3.0%
94
3.0%
97
3.0%
100
3.0%
103
3.0%
106
3.0%
109
3.1%
Self generation switching to the grid
GWh
143
3.0%
148
3.0%
152
3.0%
157
3.0%
161
3.0%
166
3.0%
171
3.0%
176
3.0%
182
3.1%
Total expected demand
Expected demand growth
GWh
%
1,086
4.7%
1,138
4.7%
1,192
4.8%
1,249
4.8%
1,310
4.8%
1,373
4.9%
1,440
4.9%
1,511
4.9%
1,585
4.9%
Non-technical
Gross generation GPL system
Average load
Peak demand
MW
MW
124
180
130
188
136
197
143
207
149
217
157
227
164
238
172
250
181
262
-105,000
-105,000
-105,000
-105,000
-105,000
-105,000
-105,000
-105,000
-105,000
AMAILA FALLS COSTS
PPA (fixed annual payment)
k USD
ECONOMIC BENEFITS
Savings in Operating Costs
Fuel Consumption
Prices
HFO (includes freight)
LFO (includes freight)
Generation mix
Year
2018
2019
2020
2021
2022
2023
2024
2025
2026
USD / bbl
USD / bbl
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
87%
13%
89%
11%
89%
11%
89%
11%
91%
9%
91%
9%
93%
7%
93%
7%
93%
7%
bbl
k USD
bbl
k USD
1,471,767
k USD
HFO
LFO
Expansion Plan without Amaila
Expansion Plan with Amaila Y 2014
Savings in Fuel Costs
O&M Expenses
O&M unit costs thermal engines
O&M Amaila Falls
USD / MWh
USD / MWh
1,535,190
1,612,524
1,685,181
1,762,496
1,845,258
1,933,409
2,027,456
2,118,201
94,730
97,036
101,924
106,516
109,665
114,814
118,392
124,151
129,708
124,573
181,473
243,363
293,850
329,687
415,171
505,191
600,174
700,286
8,018
11,470
15,382
18,574
20,514
25,832
30,935
36,752
42,882
86,712
85,565
86,541
87,943
89,151
88,982
87,457
87,399
86,826
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
Expansion Plan without Amaila
Expansion Plan with Amaila Y 2014
k USD
k USD
9,045
6,688
9,509
7,128
9,998
7,596
10,514
8,061
11,057
8,517
11,630
9,090
12,233
9,693
12,869
10,329
13,540
11,000
PPA Guysuco
Expansion Plan without Amaila
Expansion Plan with Amaila Y 2014
k USD
k USD
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
Savings in O&M Expenses
k USD
Total Savings in Operating Costs
Savings in Capital Expenditures
in Thermal Plants
Year
Investment Cost
USD / kW
Return on capital (assumes private inv
%
Repayment period
years
Module
MW
New thermal capacity additions per year
Expansion Plan without Amaila
Expansion Plan with Amaila Y 2014
Expansion Plan without Amaila
Expansion Plan with Amaila Y 2014
Fuel option - Emission Factor
Carbon bonds price
Reduction in Fuel Consumption
Reduction in CO2
tonnes
tonnes
GHG Emissions Reduction
k USD
TOTAL ECONOMIC BENEFITS
NET CASH FLOW
2,402
2,453
2,540
2,540
2,540
2,540
2,540
88,944
90,396
91,691
91,522
89,997
89,939
89,366
2018
2019
2020
2021
2022
2023
2024
2025
2026
7
14
-
14
-
14
14
14
14
14
14
21
21
MW-year
MW-year
-
k USD
k USD
22,362
1,597
25,557
1,597
27,154
1,597
30,349
1,597
33,543
1,597
36,738
4,792
39,932
7,986
43,127
11,181
47,919
15,973
20,765
23,959
25,557
28,751
31,946
31,946
31,946
31,946
31,946
Year
kg CO2 /
kg diesel
USD / t
2,381
87,946
1,100
16%
10
7
Savings in CAPEX annual payments
GHG Emissions Reduction
2,357
89,070
7
2018
14
-
2019
-
2020
2021
2022
2023
2024
2025
2026
3.07
10.43
207,261
636,290
k USD
208,264
639,371
210,640
646,665
214,051
657,136
220,432
676,727
220,013
675,441
219,726
674,558
219,582
674,116
218,141
669,692
6,637
6,669
6,745
6,854
7,058
7,045
7,036
7,031
6,985
116,471
118,574
121,245
126,001
130,695
130,512
128,978
128,916
128,297
11,471
13,574
16,245
21,001
25,695
25,512
23,978
23,916
23,297
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
51
Period 2027 - 2035
COST-BENEFIT ANALYSIS FOR AMAILA FALLS PROJECT
MAIN ASSUMPTIONS
Crude Oil Price (WTI)
Demand Forecast
GDP growth
Total Sales GPL system
T & D losses
Year
USD / bbl
2027
75
2028
75
2029
75
2030
75
2031
75
2032
75
2033
75
2034
75
2035
75
Year
%
2027
3.1%
2028
3.1%
2029
3.1%
2030
3.1%
2031
3.1%
2032
3.1%
2033
3.1%
2034
3.1%
2035
3.1%
GWh
annual growth
973
5.4%
1,025
5.4%
1,081
5.4%
1,140
5.5%
1,202
5.5%
1,268
5.5%
1,338
5.5%
1,407
5.1%
1,479
5.1%
in %
Technical
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
GWh
annual growth
1,364
5.4%
1,438
5.4%
1,516
5.4%
1,599
5.5%
1,686
5.5%
1,779
5.5%
1,876
5.5%
1,972
5.1%
2,073
5.1%
Linden Power Company
GWh
112
3.1%
116
3.1%
119
3.1%
123
3.1%
127
3.1%
131
3.1%
135
3.1%
139
2.9%
143
2.9%
Self generation switching to the grid
GWh
187
3.1%
193
3.1%
199
3.1%
205
3.1%
211
3.1%
218
3.1%
225
3.1%
232
3.1%
239
3.1%
Total expected demand
Expected demand growth
GWh
%
1,664
5.0%
1,747
5.0%
1,835
5.0%
1,927
5.0%
2,024
5.1%
2,127
5.1%
2,236
5.1%
2,342
4.8%
2,454
4.8%
Non-technical
Gross generation GPL system
Average load
Peak demand
MW
MW
190
275
199
289
209
304
220
319
231
335
243
352
255
370
-105,000
-105,000
-105,000
-105,000
-105,000
-105,000
-105,000
267
388
280
406
-
-
AMAILA FALLS COSTS
PPA (fixed annual payment)
k USD
ECONOMIC BENEFITS
Savings in Operating Costs
Fuel Consumption
Prices
HFO (includes freight)
LFO (includes freight)
Generation mix
Year
2027
2028
2029
2030
2031
2032
2033
2034
2035
USD / bbl
USD / bbl
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
93%
7%
93%
7%
94%
6%
94%
6%
94%
6%
94%
6%
94%
6%
94%
6%
94%
6%
bbl
k USD
bbl
k USD
2,224,799
2,328,772
2,440,327
2,569,007
2,696,255
2,822,829
2,967,920
3,109,691
3,250,374
136,235
142,602
148,230
156,046
163,775
171,464
180,277
188,888
197,433
805,835
917,081
1,034,710
1,158,848
1,289,687
1,427,867
1,573,727
1,716,791
1,866,848
49,345
56,157
62,850
70,390
78,338
86,731
95,591
104,281
113,396
k USD
86,890
86,445
85,380
85,656
85,437
84,732
84,686
84,607
84,038
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
HFO
LFO
Expansion Plan without Amaila
Expansion Plan with Amaila Y 2014
Savings in Fuel Costs
O&M Expenses
O&M unit costs thermal engines
O&M Amaila Falls
USD / MWh
USD / MWh
Expansion Plan without Amaila
Expansion Plan with Amaila Y 2014
k USD
k USD
14,248
11,708
14,993
12,453
15,782
13,242
16,614
14,074
17,491
14,951
18,417
15,877
19,394
16,854
20,353
17,813
21,359
18,819
PPA Guysuco
Expansion Plan without Amaila
Expansion Plan with Amaila Y 2014
k USD
k USD
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
Savings in O&M Expenses
k USD
Total Savings in Operating Costs
Savings in Capital Expenditures
in Thermal Plants
Year
Investment Cost
USD / kW
Return on capital (assumes private inv
%
Repayment period
years
Module
MW
New thermal capacity additions per year
Expansion Plan without Amaila
Expansion Plan with Amaila Y 2014
Expansion Plan without Amaila
Expansion Plan with Amaila Y 2014
MW-year
MW-year
Savings in CAPEX annual payments
Year
Fuel option - Emission Factor
Carbon bonds price
kg CO2 /
kg diesel
USD / t
Reduction in Fuel Consumption
Reduction in CO2
tonnes
tonnes
GHG Emissions Reduction
k USD
TOTAL ECONOMIC BENEFITS
NET CASH FLOW
2,540
2,540
2,540
2,540
2,540
2,540
2,540
2,540
88,985
87,920
88,196
87,977
87,272
87,226
87,147
86,578
2027
2028
2029
2030
2031
2032
2033
2034
2035
14
14
21
21
21
21
14
14
21
21
28
28
21
21
21
21
28
28
51,113
19,168
55,905
23,959
60,697
28,751
63,892
31,946
68,684
36,738
75,073
43,127
79,865
47,919
84,656
52,711
91,046
59,100
31,946
31,946
31,946
31,946
31,946
31,946
31,946
31,946
31,946
1,100
16%
10
7
k USD
k USD
GHG Emissions Reduction
2,540
89,430
2027
2028
2029
2030
2031
2032
2033
2034
2035
3.07
10.43
218,302
670,188
k USD
217,183
666,752
216,249
663,883
216,948
666,029
216,395
664,333
214,610
658,851
214,491
658,488
214,292
657,877
212,850
653,450
6,990
6,954
6,924
6,947
6,929
6,872
6,868
6,862
6,815
128,366
127,885
126,790
127,088
126,852
126,090
126,040
125,955
125,339
23,366
22,885
21,790
22,088
21,852
21,090
21,040
125,955
125,339
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
52
Period 2036 - 2044
COST-BENEFIT ANALYSIS FOR AMAILA FALLS PROJECT
MAIN ASSUMPTIONS
Crude Oil Price (WTI)
Demand Forecast
GDP growth
Total Sales GPL system
T & D losses
Year
USD / bbl
2036
75
2037
75
2038
75
2039
75
2040
75
2041
75
2042
75
2043
75
2044
75
Year
%
2036
3.1%
2037
3.1%
2038
3.1%
2039
3.1%
2040
3.1%
2041
3.1%
2042
3.1%
2043
3.1%
2044
3.1%
GWh
annual growth
1,555
5.1%
1,635
5.1%
1,719
5.1%
1,808
5.1%
1,901
5.1%
1,999
5.1%
2,102
5.1%
2,210
5.1%
2,324
5.1%
in %
Technical
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
GWh
annual growth
2,178
5.1%
2,290
5.1%
2,407
5.1%
2,530
5.1%
2,659
5.1%
2,795
5.1%
2,938
5.1%
3,088
5.1%
3,246
5.1%
Linden Power Company
GWh
147
2.9%
151
2.9%
155
2.9%
160
2.9%
164
2.9%
169
2.9%
174
2.9%
179
2.9%
184
2.9%
Self generation switching to the grid
GWh
246
3.1%
254
3.1%
262
3.1%
270
3.1%
278
3.1%
287
3.1%
296
3.1%
305
3.1%
314
3.1%
Total expected demand
Expected demand growth
GWh
%
2,571
4.8%
2,694
4.8%
2,824
4.8%
2,959
4.8%
3,102
4.8%
3,251
4.8%
3,408
4.8%
3,572
4.8%
3,745
4.8%
Non-technical
Gross generation GPL system
Average load
Peak demand
MW
MW
294
425
308
446
322
467
338
490
354
513
371
538
389
564
408
591
427
620
-
-
-
-
-
-
-
-
-
AMAILA FALLS COSTS
PPA (fixed annual payment)
k USD
ECONOMIC BENEFITS
Savings in Operating Costs
Fuel Consumption
Prices
HFO (includes freight)
LFO (includes freight)
Generation mix
Year
2036
2037
2038
2039
2040
2041
2042
2043
2044
USD / bbl
USD / bbl
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
94%
6%
95%
5%
95%
5%
95%
5%
95%
5%
95%
5%
95%
5%
95%
5%
95%
5%
bbl
k USD
bbl
k USD
3,399,778
3,567,730
3,736,428
3,905,874
4,095,362
4,286,636
4,492,588
4,706,920
4,934,195
206,508
214,951
225,115
235,323
246,740
258,264
270,672
283,585
297,278
2,024,246
2,189,349
2,362,988
2,545,165
2,736,305
2,936,857
3,147,290
3,368,098
3,599,801
122,956
131,905
142,367
153,343
164,859
176,941
189,620
202,923
216,883
k USD
83,552
83,045
82,748
81,981
81,881
81,322
81,052
80,662
80,395
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
HFO
LFO
Expansion Plan without Amaila
Expansion Plan with Amaila Y 2014
Savings in Fuel Costs
O&M Expenses
O&M unit costs thermal engines
O&M Amaila Falls
USD / MWh
USD / MWh
Expansion Plan without Amaila
Expansion Plan with Amaila Y 2014
k USD
k USD
22,414
19,874
23,520
20,980
24,684
22,144
25,905
23,365
27,186
24,646
28,530
25,990
29,941
27,401
31,420
28,880
32,973
30,433
PPA Guysuco
Expansion Plan without Amaila
Expansion Plan with Amaila Y 2014
k USD
k USD
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
Savings in O&M Expenses
k USD
Total Savings in Operating Costs
Savings in Capital Expenditures
in Thermal Plants
Year
Investment Cost
USD / kW
%
Return on capital (assumes private inv
Repayment period
years
Module
MW
New thermal capacity additions per year
Expansion Plan without Amaila
Expansion Plan with Amaila Y 2014
Expansion Plan without Amaila
Expansion Plan with Amaila Y 2014
MW-year
MW-year
Savings in CAPEX annual payments
Year
Fuel option - Emission Factor
Carbon bonds price
kg CO2 /
kg diesel
USD / t
Reduction in Fuel Consumption
Reduction in CO2
tonnes
tonnes
GHG Emissions Reduction
k USD
TOTAL ECONOMIC BENEFITS
NET CASH FLOW
2,540
2,540
2,540
2,540
2,540
2,540
2,540
2,540
85,585
85,288
84,521
84,421
83,862
83,592
83,202
82,935
2036
2037
2038
2039
2040
2041
2042
2043
2044
28
28
21
21
28
28
35
35
28
28
35
35
35
35
35
35
35
35
97,435
65,489
102,227
70,281
108,616
76,670
119,797
87,851
126,186
94,240
134,173
102,227
142,159
110,213
150,145
118,200
158,132
126,186
31,946
31,946
31,946
31,946
31,946
31,946
31,946
31,946
31,946
1,100
16%
10
7
k USD
k USD
GHG Emissions Reduction
2,540
86,092
2036
2037
2038
2039
2040
2041
2042
2043
2044
3.07
10.43
211,620
649,675
k USD
212,059
651,020
211,298
648,686
209,340
642,673
209,086
641,893
207,658
637,511
206,969
635,395
205,973
632,336
205,291
630,244
6,776
6,790
6,766
6,703
6,695
6,649
6,627
6,595
6,573
124,814
124,321
123,999
123,170
123,062
122,457
122,165
121,743
121,455
124,814
124,321
123,999
123,170
123,062
122,457
122,165
121,743
121,455
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
53
Period 2045 – 2053
COST-BENEFIT ANALYSIS FOR AMAILA FALLS PROJECT
MAIN ASSUMPTIONS
Crude Oil Price (WTI)
Demand Forecast
GDP growth
Total Sales GPL system
T & D losses
Year
USD / bbl
2045
75
2046
75
2047
75
2048
75
2049
75
2050
75
2051
75
2052
75
2053
75
Year
%
2045
3.1%
2046
3.1%
2047
3.1%
2048
3.1%
2049
3.1%
2050
3.1%
2051
3.1%
2052
3.1%
2053
3.1%
GWh
annual growth
2,443
5.1%
2,569
5.1%
2,701
5.1%
2,840
5.1%
2,986
5.1%
3,140
5.1%
3,302
5.1%
3,472
5.1%
3,650
5.1%
in %
Technical
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
GWh
annual growth
3,412
5.1%
3,587
5.1%
3,770
5.1%
3,963
5.1%
4,166
5.1%
4,379
5.1%
4,603
5.1%
4,838
5.1%
5,086
5.1%
Linden Power Company
GWh
190
2.9%
195
2.9%
201
2.9%
207
2.9%
213
2.9%
219
2.9%
225
2.9%
232
2.9%
238
2.9%
Self generation switching to the grid
GWh
324
3.1%
334
3.1%
344
3.1%
355
3.1%
366
3.1%
377
3.1%
389
3.1%
401
3.1%
413
3.1%
Total expected demand
Expected demand growth
GWh
%
3,926
4.8%
4,116
4.8%
4,315
4.8%
4,524
4.8%
4,744
4.9%
4,975
4.9%
5,217
4.9%
5,470
4.9%
5,737
4.9%
Non-technical
Gross generation GPL system
Average load
Peak demand
MW
MW
448
649
470
681
493
714
516
749
542
785
568
823
595
863
624
905
655
949
-
-
-
-
-
-
-
-
-
AMAILA FALLS COSTS
PPA (fixed annual payment)
k USD
ECONOMIC BENEFITS
Savings in Operating Costs
Fuel Consumption
Prices
HFO (includes freight)
LFO (includes freight)
Generation mix
Year
2045
2046
2047
2048
2049
2050
2051
2052
2053
USD / bbl
USD / bbl
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
61.9
97.4
95%
5%
95%
5%
95%
5%
95%
5%
95%
5%
95%
5%
95%
5%
95%
5%
95%
5%
bbl
k USD
bbl
k USD
5,165,464
5,418,128
5,685,898
5,966,914
6,261,839
6,571,373
6,896,246
7,237,230
7,595,132
311,212
326,435
342,567
359,498
377,267
395,916
415,489
436,033
457,596
3,842,944
4,098,100
4,365,869
4,646,885
4,941,811
5,251,344
5,576,218
5,917,201
6,275,104
231,532
246,905
263,037
279,968
297,737
316,386
335,959
356,503
378,066
k USD
79,680
79,530
79,530
79,530
79,530
79,530
79,530
79,530
79,530
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
9.0
6.4
HFO
LFO
Expansion Plan without Amaila
Expansion Plan with Amaila Y 2014
Savings in Fuel Costs
O&M Expenses
O&M unit costs thermal engines
O&M Amaila Falls
USD / MWh
USD / MWh
Expansion Plan without Amaila
Expansion Plan with Amaila Y 2014
k USD
k USD
34,603
32,063
36,313
33,773
38,108
35,568
39,991
37,451
41,968
39,428
44,042
41,502
46,220
43,680
48,505
45,965
50,904
48,364
PPA Guysuco
Expansion Plan without Amaila
Expansion Plan with Amaila Y 2014
k USD
k USD
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
9,007
Savings in O&M Expenses
k USD
Total Savings in Operating Costs
Savings in Capital Expenditures
in Thermal Plants
Year
Investment Cost
USD / kW
%
Return on capital (assumes private inv
Repayment period
years
Module
MW
New thermal capacity additions per year
Expansion Plan without Amaila
Expansion Plan with Amaila Y 2014
Expansion Plan without Amaila
Expansion Plan with Amaila Y 2014
MW-year
MW-year
Savings in CAPEX annual payments
Year
Fuel option - Emission Factor
Carbon bonds price
kg CO2 /
kg diesel
USD / t
Reduction in Fuel Consumption
Reduction in CO2
tonnes
tonnes
GHG Emissions Reduction
k USD
TOTAL ECONOMIC BENEFITS
NET CASH FLOW
2,540
2,540
2,540
2,540
2,540
2,540
2,540
2,540
82,070
82,070
82,070
82,070
82,070
82,070
82,070
82,070
2045
2046
2047
2048
2049
2050
2051
2052
2053
42
42
42
42
42
42
42
42
49
49
49
49
56
56
56
56
56
56
169,313
137,367
178,897
146,951
188,480
156,535
198,064
166,118
210,843
178,897
222,024
190,078
236,399
204,453
249,178
217,232
261,956
230,010
31,946
31,946
31,946
31,946
31,946
31,946
31,946
31,946
31,946
1,100
16%
10
7
k USD
k USD
GHG Emissions Reduction
2,540
82,220
2045
2046
2047
2048
2049
2050
2051
2052
2053
3.07
10.43
203,465
624,636
k USD
203,081
623,460
203,081
623,460
203,081
623,460
203,081
623,460
203,081
623,460
203,081
623,460
203,081
623,460
203,081
623,460
6,515
6,503
6,503
6,503
6,503
6,503
6,503
6,503
6,503
120,681
120,518
120,518
120,518
120,518
120,518
120,518
120,518
120,518
120,681
120,518
120,518
120,518
120,518
120,518
120,518
120,518
120,518
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
54
4.5.
OPPORTUNITY COST FOR GPL (MAXIMUM ANNUAL FIXED PAYMENT)
ME also estimated the maximum fixed annual payment (GPL’s opportunity cost) for
Amaila’s output which verifies that the present value of GPL’s total generation
expenses (CAPEX and OPEX) is equal in both capacity expansion options analyzed.
The said annual fixed payment is – 122,724 k USD, considering Base Case
assumptions.
Even though this ceiling fixed annual payment assures Amaila’s structural
competitiveness compared to GPL’s thermal expansion option (opportunity cost), it also
creates a financial constraint on GPL in the short to medium term: supply costs
including Amaila are higher than supply costs deselecting Amaila as a candidate
project.
In turn, high average supply costs relative to other supply choices, discourage market
expansion and increases demand risk for GPL.
Therefore, ME re-estimated the maximum payment assuming a relative more
conservative scenario: no self generators decide to purchase power from GPL
(because there would be no room for tariff incentives) and a higher discount rate (14%)
than Base Case because GPL’s demand risk increases: such conditions make the
annual fixed payment to drop down to – 106,785 k USD.
The table below summarizes key assumptions for each estimated maximum fixed
annual payment:
Crude Oil (USD /
bbl)
Base Case
75
75
Discount Rate
12%
14%
Demand
GPL's maximum
annual payment for
Amaila's output
same as Base Case
without self generators
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
-122,724
-106,785
# of initial years
when costs
exceeds benefits
20
7
55
SECTION IV: COMPETITIVENESS OF AMAILA FALLS SUPPLY COST
In this Section, ME compares GPL’s supply cost and cost of self generation to discuss
the competitiveness of the project in the short run.
In the medium to long term, assuming crude oil prices of 75 USD / bbl, GPL’s average
supply costs including Amaila Falls in its expansion plan are lower than the alternative
expansion option (diesel-fired generators).
5. GPL SUPPLY COST
Amaila Falls hydro power plant project will sell its energy output primarily to GPL, at a
fixed annual payment of -105,000 k USD, regardless actual demand. In other words,
the power purchase agreement is a take-or-pay contract.
Amaila Falls project will be competitive if other supply options available for GPL (or any
other off-taker) have higher prices than Amaila’s supply cost (PPA).
GPL’s alternative (to Amaila Falls) supply cost is the long run marginal cost (LRMC) of
the most competitive thermal technology available to expand its power system (bunkerfired engines). Such LRMC is in between 13.0 and 14.0 ¢USD / kWh, assuming a
crude oil price (WTI) of 75 USD / bbl and expected dispatch around 70 %.
As shown with the economic indicators of the cost-benefit analysis, the inclusion of
Amaila Falls in GPL’s generation expansion plan lowers the net present value of GPL’s
generation expenses.
The inclusion of Amaila Falls cuts down GPL’s average supply costs to 11.5 ¢USD /
kWh in the medium to long term.
However, in the early years of the project (first year of Amaila’s operation in the Base
Case) and given that contractual arrangement is take-or-pay, GPL’s total generating
expenses including the power purchase agreement with Amaila Falls are closer or
even 5 - 10 % higher than GPL’s generation expenses without including Amaila Falls
(and only adding needed thermal generators to meet demand growth):
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
56
GPL's generating expenses per unit of demand
With and without Amaila Falls in the expansion plan
16.0
15.5
15.0
14.5
14.0
100 % Thermal Expansion
in cUSD / kWh
13.5
13.0
12.5
12.0
11.5
Expansion with Amaila as of Y 2014
(includes carbon credits)
11.0
10.5
10.0
Y 2014:
Amaila Falls begins commercial operations
9.5
20
36
20
37
20
34
20
35
20
32
20
33
20
30
20
31
20
28
20
29
20
26
20
27
20
24
20
25
20
23
20
21
20
22
20
19
20
20
20
17
20
18
20
15
20
16
20
13
20
14
20
11
20
12
20
09
20
10
9.0
This short run effect can be mitigated with a more aggressive market expansion
because the fixed annual payment is distributed among a larger demand.
In any case, GPL’s degree of success in attracting industrial self generators back to the
grid, will mostly depend on the tariff12 at which GPL can deliver the energy to such
customers compared to their self-generation cost.
6. COST OF SELF GENERATION
Based on data collected in the self generators survey and own assumptions regarding
typical heat content and machine efficiency, ME estimated the development cost of
self-generation as the sum of its variable costs of production and its investment cost.
The following table summarizes the set of assumptions adopted to estimate the cost of
self generation:
Investment Cost
600 USD / kW
Repayment period
10 years
O&M
4.0 USD / MWh
Type of fuel
Light fuel oil
Fuel cost on site
97.4 USD / bbl
Gross capacity
200 – 1000 kVA
Heat rate
33 - 36 %
Expected dispatch
70 %
12
Reliability of service will also play a key role in market expansion
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
57
The estimated self generation costs are:
•
between 19.3 and 20.7 ¢USD / kWh, for an industry assessing the costs of
installing a new power generator.
•
between 15.8 and 17.2 ¢USD / kWh for existing self generators (does not
include investment cost – sunk cost -, only operating costs).
The above estimated self generation costs represent the break-even price for an
industrial customer, assuming same reliability in supply options (GPL vs self
generation).
The cost of self generation (both for prospective and existing self generators as well) is
higher than GPL’s average supply costs.
It’s worth noting that these figures are not directly comparable with GPL’s supply cost
(transmission and distribution charges have to be added).
GPL's generating expenses and Costs of self generation
21.0
20.5
20.0
19.5
Prospective self generator
Total costs (includes capital expenditures)
19.0
18.5
18.0
17.5
in cUSD / kWh
17.0
16.5
Existing self generators
Variable costs
16.0
15.5
15.0
14.5
14.0
13.5
100 % Thermal Expansion
13.0
12.5
12.0
11.5
11.0
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
20
36
20
37
20
34
20
35
20
32
20
33
20
30
20
31
20
28
20
29
20
26
20
27
20
24
20
25
20
23
20
21
20
22
20
19
20
20
20
17
20
18
20
16
20
14
20
15
20
13
20
09
20
10
10.0
Expansion with Amaila as of Y 2014
Note: GPL's generating expenses
(T&D charges are not included)
20
11
20
12
10.5
58
SECTION V: SENSITIVITY ANALYSIS
Based on the cost benefit analysis developed for the Base Case, ME identified the
main factors that negatively influence the economic rationale of the project:
• Fuel prices
• Demand growth / market expansion in the short run
7. SENSITIVITY TO CRUDE OIL PRICE
Variable operating costs for thermal plants mostly depend on fuel costs. Direct savings
in fuel costs account for approximately 70 % of total economic benefits of Amaila Falls
project. In turn, fuel prices are positively correlated to crude oil prices.
Future scenarios of high crude oil prices will be an upside for Amaila Falls project.
Conversely, scenarios of low crude oil prices are a downside.
The following table shows the project’s net present value and economic rate of return
(ERR) for different scenarios of future crude oil prices (with and without including
carbon credits as economic benefit):
Sensitivity to WTI (net cash flow includes carbon credits).-
Crude Oil price NPV (@ 12%)
Base Case (*)
Downside Cases
USD / bbl
75
70
65
60
55
k USD
186,886
145,052
103,217
61,383
19,549
ERR
BCR (**)
in %
83%
37%
23%
17%
13%
0.70
0.67
0.64
0.61
0.58
# of initial years with
negative cash flow
(cost > benefits)
1
2
4
6
8
(*) consistent with World Bank's latest projections
(**) Benefit - Cost ratio = NPV (Benefits) / NPV (Costs)
Time horizon: 40 years
Sensitivity to WTI (net cash flow does not include carbon credits).-
Crude Oil price NPV (@ 12%)
Base Case (*)
Downside
Cases
USD / bbl
75
70
65
60
55
k USD
132,390
90,556
48,721
6,887
-34,947
ERR
in %
32%
21%
16%
12%
10%
BCR (**)
0.66
0.63
0.60
0.57
0.54
# of initial years with
negative cash flow
(cost > benefits)
3
5
7
8
20
The number of initial years with negative cash flow (i.e. costs greater than benefits)
increase as WTI decreases, because direct savings in fuel costs are reduced. In other
words, scenarios of relative low crude oil prices reduce the competitiveness of hydro
projects vis a vis thermal expansion.
Assuming no economic benefits from carbon emission reduction and expected crude
oil prices lower than 60 USD / bbl, drastically reduce direct savings in fuel costs with
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
59
respect to Base Case; and project’s net cash flow turns negative until termination of
PPA (20 years).
8. SENSITIVITY TO MARKET EXPANSION
In the short run, annual fixed payment for Amaila’s output may outweigh the direct
savings in operating costs and capital expenditures in new thermal generators. Instead,
in the medium to long run benefits offset the costs.
Market expansion contributes to compensate the temporary imbalance between total
costs and total benefits.
The following table shows the project’s economic indicators for different scenarios of
market expansion:
Sensitivity to market expansion
Scenario
Base Case (*)
Upside Case
Self generators
switching to the grid
GWh-year
131 GWh (60 % in 2014
& 40 % in 2015)
NPV (@ 12%)
Economic rate
of return (ERR)
Benefit / Cost
ratio
k USD
in %
BCR
# of initial years with
negative cash flow
(costs larger than
benefits)
186,252
94%
0.70
192,463
positive cash flow
all years
0.71
105 GWh as of Y 2014
171,656
55%
0.69
2
79 GWh as of Y 2014
156,160
37%
0.68
3
109,313
21%
0.65
7
131 GWh as of Y 2014
1
zero
Downside Cases:
20% less than BC
40 % less than BC
Self generators decide not to switch to the grid
8.1.
UPSIDE CASE
If it is assumed that 100 % of the estimated demand from self generation (131 GWhyear) is connected to the grid during the first year (2014) of Amaila Falls operation,
benefits are greater than costs (compared to – 5,800 thousand USD in Base Case):
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
60
GPL's generating expenses per unit of demand
With and without Amaila Falls in the expansion plan
16.0
15.5
15.0
14.5
14.0
100 % Thermal Expansion
in cUSD / kWh
13.5
13.0
12.5
12.0
11.5
Expansion with Amaila as of Y 2014
(includes carbon credits)
11.0
10.5
10.0
Y 2014:
Amaila Falls begins commercial operations
9.5
8.2.
20
36
20
37
20
34
20
35
20
32
20
33
20
30
20
31
20
28
20
29
20
26
20
27
20
24
20
25
20
23
20
21
20
22
20
19
20
20
20
17
20
18
20
15
20
16
20
13
20
14
20
11
20
12
20
09
20
10
9.0
DOWNSIDE CASE
On the contrary, assuming there are no firms interested in being supplied by GPL
instead of self generating (and despite the cost differential), Amaila’s cash flow turns
negative for seven years, as seen in the graph below:
GPL's generating expenses per unit of demand
With and without Amaila Falls in the expansion plan
16.0
15.5
15.0
14.5
14.0
100 % Thermal Expansion
in cUSD / kWh
13.5
13.0
12.5
12.0
11.5
Expansion with Amaila as of Y 2014
(includes carbon credits)
11.0
10.5
10.0
Y 2014:
Amaila Falls begins commercial operations
9.5
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
20
36
20
37
20
34
20
35
20
32
20
33
20
30
20
31
20
28
20
29
20
26
20
27
20
24
20
25
20
23
20
21
20
22
20
19
20
20
20
17
20
18
20
15
20
16
20
13
20
14
20
11
20
12
20
09
20
10
9.0
61
SECTION VI: REVIEW OF EXISTING HYDROLOGY STUDIES
Existing studies on the hydrology and project design were reviewed in order to verify
the conclusions outlined by MWH and to assess possible design enhancements based
on available field data.
The review of hydrology studies included the following documents submitted by the
Client:
• Amaila Falls Hydroelectric Project – Guyana - Feasibility Study Report –
Hydrology - Prepared by MWH – December 2001
• Amaila Falls Hydro - Estimated Monthly Energy and Average Power for a Range
of Load Factors – Prepared by MWH – August 2009
• GEOTECHNICAL BASELINE REPORT FOR BIDDING Hydroelectric Power Project – Generating Facilities - June 2008
Amaila
Falls
• Amaila Falls Hydroelctric Project – Generating Facilities – Section 8 – Owners
Requirement Drawings – June 2008
• PPA multiscenarioCovermemo_20090820.pdf
See Annex II for a complete description of the hydrology and design aspects reviewed.
Main conclusions are summarized below:
The design of Amaila Falls Project encountered several problems arising from the lack
of hydrologic data. Therefore, the best techniques available were applied to cope with
the lack of information but even so, several questions remained unanswered, such as
the following:
• The flows used were obtained by extrapolating the results from Kaieter Falls
Station with different transfer coefficients and then adopting 0.30 without further
justification. This may cause some uncertainty regarding the expected power
generation.
• The maximum flow adopted to design the dam was the result of transforming the
Probable Maximum Precipitation value into the Probable Maximum Flow by
adopting a C coefficient (Creaguer’s formula) that has no direct justification, thus
causing uncertainty as regards the maximum flow adopted for the design at 5.010
m3/s.
• In addition, the Probable Maximum Flood was assessed in the current basin
status, with no deforestation or mining exploitation. Any modification of the basin
in such respect will have an impact on the increase in the maximum value
considered.
• The flows assumed for different return periods, which set the maximum values to
be adopted during the construction period, also include coefficients and
parameters adopted without any actual data on the site.
• In order to obtain more accurate information, it would be desirable to install a
hydro-meteorological station in a section of the river that is representative of the
Project. Even if the works start soon, the information obtained will always be
useful and will allow future adjustment of the parameters necessary for operation.
With respect to the studies conducted on the behavior of generation with different dam
heights and installed capacities, it was concluded that:
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
62
• Energy production is marked by hydraulicity in the different months of the year. In
wet months (June to September), more power can be generated and demand is
covered.
• In months with low hydraulicity, demand is only partially covered.
• The above shows the reservoir’s poor regulation, considering that in wet months
or periods the surplus flows will be spilled.
• As the reservoir level is increased (more regulation) or installed capacity is
reduced, the percentage of demand coverage grows for the same load factor.
• In the actual case, 140 MW at delivery point and maximum reservoir level at
462.00 m.a.s.l., the trend is confirmed: even with smaller load factors, there is a
deficit in power generation in months with low hydraulicity.
The potential increase in dam height will have little influence on the installed capacity
due to the great existing fall, although it will improve annual power generation,
considering the greater regulation capacity and the following features:
• The increase in the maximum level from 462 to 468 m represents an increase of
26 % in the maximum height of Amaila Dam and 30 % in Kuribrong Dam, with
major economic implications.
• In addition to more investment, other aspects linked to the larger flooded area
should be considered, in particular, associated environmental aspects.
• Another alternative to enhance the dam’s regulation capacity, and therefore its
annual average energy, could be the implementation of circular sector gates
allowing some of the flows in wet months to be stored, thus reducing spilling.
• It is considered, however, that this additional regulation capacity would be limited
and equal to approximately only 10% of the annual spilling.
• The convenience of installing gates to reduce the expected investment remains
to be considered.
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
63
SECTION VII: MAIN CONCLUSIONS
Amaila Falls project brings structural benefits to the power system: a generation mix
hydro-thermal is better to hedge risks (oil prices volatility) than a system that entirely
relies on thermal plants.
Cost – benefit analysis
It evidences that the project is economically profitable. The inclusion of Amaila Falls in
GPL’s expansion plan reduces GPL’s net present value of generation expenses
throughout the study time horizon.
In other words, total benefits outweigh total costs of the project.
It’s worth noting that Amaila Falls benefits are mainly concentrated in the medium to
long term, while PPA is evenly distributed during 20 years.
Assuming a WTI of 75 USD / bbl, an annual demand growth of 5 % in the steady state
(consistent with a GDP growth of 3.0 %) and the addition to the grid of 131 GWh
currently self generating (60 % in 2014 and 40 % in 2015), the project’s economic
indicators are the following:
NPV (kUSD) (@ 12%)
ERR
Benefit - Cost Ratio BCR
186,886
83%
0.70
Due to plant’s size (larger than 20 MW), Amaila Falls may not be eligible for carbon
credits. If carbon credits are not considered in the project’s benefits, the above
economic indicators are the following:
NPV (kUSD) (@ 12%)
ERR
Benefit - Cost Ratio BCR
132,390
32%
0.66
GPL’s alternative supply cost is the long run marginal cost (LRMC) of the most
competitive thermal technology available to expand its power system (bunker-fired
engines). Such LRMC is in between 13.0 and 14.0 ¢USD / kWh, assuming a crude oil
price (WTI) of 75 USD / bbl.
Competitiveness
The consideration of Amaila Falls in the capacity expansion plan at a fixed annual
payment of 105,000 k USD lowers the NPV of GPL’s generation expenses throughout
the study time horizon, as demonstrated in the cost-benefit analysis.
The inclusion of Amaila Falls cuts down GPL’s average supply costs to 11.5 ¢USD /
kWh in the medium to long term.
In the short run, GPL’s average supply costs are higher than in the long term, in the
order of 12.6 ¢USD / kWh (effect of a take-or-pay contractual arrangement and
demand lower or close to energy delivered).
Market expansion by attracting industrial self generators back to the grid mitigates this
short run effect because the fixed annual payment is absorbed by a larger demand.
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
64
Costs of self-generation (assuming a crude oil price of 75 USD / bbl) are estimated
between 15.8 and 20.7 ¢USD / kWh. These figures represent represent the break-even
price for an industrial customer, assuming same reliability in supply options (GPL vs
self generation).
Costs of self generation are higher than GPL’s average supply costs. It’s worth noting
that these figures are not directly comparable with GPL’s supply cost (transmission and
distribution charges have to be added).
Sensitivity to WTI
Future scenarios of high crude oil prices contribute to increase the competitiveness of
Amaila Falls vis a vis the thermal expansion (upside). Conversely, scenarios of low
crude oil prices are a downside for the project.
The following tables show the economic indicators of the cost-benefit analysis for
different scenarios of future crude oil prices, with and without considering carbon
credits as part of the total benefits:
Sensitivity to WTI (net cash flow includes carbon credits).-
Crude Oil price NPV (@ 12%)
Base Case (*)
Downside Cases
USD / bbl
75
70
65
60
55
k USD
186,886
145,052
103,217
61,383
19,549
ERR
BCR (**)
in %
83%
37%
23%
17%
13%
0.70
0.67
0.64
0.61
0.58
# of initial years with
negative cash flow
(cost > benefits)
1
2
4
6
8
(*) consistent with World Bank's latest projections
(**) Benefit - Cost ratio = NPV (Benefits) / NPV (Costs)
Time horizon: 40 years
Sensitivity to WTI (net cash flow does not include carbon credits).-
Crude Oil price NPV (@ 12%)
Base Case (*)
Downside
Cases
USD / bbl
75
70
65
60
55
k USD
132,390
90,556
48,721
6,887
-34,947
ERR
in %
32%
21%
16%
12%
10%
BCR (**)
0.66
0.63
0.60
0.57
0.54
# of initial years with
negative cash flow
(cost > benefits)
3
5
7
8
20
The number of initial years with negative cash flow (i.e. costs greater than benefits)
increase as WTI decreases, because direct savings in fuel costs are reduced.
If one assumes no economic benefits from carbon emission reduction and expected
crude oil prices lower than 60 USD / bbl, it drastically reduce direct savings in fuel costs
with respect to Base Case; and project’s net cash flow turns negative until termination
of PPA (20 years).
Sensitivity to market expansion
In the short run, annual fixed payment for Amaila’s output may outweigh the direct
savings in operating costs and capital expenditures in new thermal generators. Instead,
in the medium to long run benefits offset the costs.
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
65
Market expansion contributes to compensate the temporary imbalance between total
costs and total benefits.
The following table shows the project’s economic indicators for different scenarios of
market expansion:
Sensitivity to market expansion
Scenario
Base Case (*)
Upside Case
Self generators
switching to the grid
GWh-year
131 GWh (60 % in 2014
& 40 % in 2015)
NPV (@ 12%)
Economic rate
of return (ERR)
Benefit / Cost
ratio
k USD
in %
BCR
# of initial years with
negative cash flow
(costs larger than
benefits)
186,886
83%
0.70
195,664
positive cash flow
all years
0.71
105 GWh as of Y 2014
170,318
49%
0.69
2
79 GWh as of Y 2014
153,363
34%
0.68
3
100,870
19%
0.64
7
131 GWh as of Y 2014
1
zero
Downside Cases:
20% less than BC
40 % less than BC
Self generators decide not to switch to the grid
The number of initial years with negative cash flow (i.e. costs greater than benefits)
increases as market expansion decreases.
High supply costs in the short run might also be mitigated considering efficient
contractual arrangements (fuel cost deduction during dry seasons, increasing annuity
over time, etc.).
Upside: If it is assumed that 100 % of the estimated demand from self generation (131
GWh-year) is connected to the grid during the first year (2014) of Amaila Falls
operation, benefits are greater than costs in the first year since the first year of Amaila’s
operation (compared to – 5,500 thousand USD in Base Case).
Downside: on the contrary, assuming there are no firms interested in being supplied by
GPL instead of self generating (and despite the cost differential), costs offset benefits
during seven years.
Review on hydrology studies
The hydrology study done by MWH encountered some difficulties due to lack of direct
hydrological data at the project site. Given the above mentioned constraint, MWH
applied best practices to process the available information.
Reservoir operation: Seasonal regulation and production of firm energy during drier
months is limited.
The optimization of the project design is limited because all available data has been
already considered. Design improvements would require additional hydrological data
collection.
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
66
ANNEX I – SIMULATION MODEL OUTPUTS
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
67
Simulation Model output: Generation balance without including Amaila Falls among selected candidates
Period 2009 - 2022
SIMULATION MODEL OUTPUT (GENERATION BALANCE) - Option without including Amaila Falls among selected candidates
ASSUMPTIONS - Base Case
Demand Forecast
Total Sales GPL system
T & D losses
Year
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
GWh
annual growth
393
418
6.3%
431
3.2%
453
5.0%
476
5.1%
500
5.1%
525
5.1%
552
5.1%
581
5.2%
611
5.2%
643
5.2%
677
5.2%
712
5.3%
750
5.3%
in %
Technical
11.4%
10.6%
9.9%
9.3%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
Non-technical
21.6%
19.4%
17.5%
15.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
Gross generation GPL system
GWh
587
597
619
647
673
701
737
775
815
857
902
949
999
1,052
Linden Power Company
GWh
66
68
70
72
74
76
79
81
83
86
88
91
94
97
Self generation switching to the grid
GWh
79
131
135
139
143
148
152
157
161
Total expected demand
Expected demand growth
GWh
%
653
665
1.8%
689
3.6%
719
4.3%
748
4.0%
MW
MW
75
108
76
110
79
114
82
119
85
124
Average load
Peak demand
-
-
-
-
-
856
14.5%
98
142
947
10.6%
991
4.7%
1,037
4.7%
1,086
4.7%
1,138
4.7%
1,192
4.8%
1,249
4.8%
1,310
4.8%
108
157
113
164
118
172
124
180
130
188
136
197
143
207
149
217
GENERATION BALANCE - WITHOUT INCLUDING AMAILA AMONG SELECTED PROJECT CANDIDATES TO EXPAND THE SYSTEM
DISPATCH OF POWER PLANTS:
Exisiting Thermal Power Plants
Guysuco Cogenerator (PPA)
New Thermal Facilities
Total Generation
GWh
GWh
GWh
GWh
614
39
653
584
81
665
608
81
689
601
81
37
719
629
81
37
748
515
81
261
856
494
81
372
947
500
81
409
991
472
81
484
1,037
484
81
521
1,086
461
81
596
1,138
478
81
633
1,192
461
81
707
1,249
447
81
782
1,310
MW
MW
MW
143
143
147
147
139
139
135
7
142
132
132
132
42
174
174
21
195
195
7
202
202
14
216
216
7
223
223
14
237
237
7
244
244
14
258
258
14
272
%
32%
34%
22%
19%
23%
25%
23%
26%
24%
26%
24%
25%
26%
GENERATION CAPACITY:
Existing thermal
Annual Thermal new additions
Total Installed Capacity
Reserve margin (Installed Capacity /
Peak demand)
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
7%
68
Simulation Model output: Generation balance without including Amaila Falls among selected candidates
Period 2023 - 2036
SIMULATION MODEL OUTPUT (GENERATION BALANCE) - Option without including Amaila Falls among selected candidates
ASSUMPTIONS - Base Case
Demand Forecast
Total Sales GPL system
T & D losses
Year
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
GWh
annual growth
790
5.3%
832
5.3%
876
5.3%
923
5.4%
973
5.4%
1,025
5.4%
1,081
5.4%
1,140
5.5%
1,202
5.5%
1,268
5.5%
1,338
5.5%
1,407
5.1%
1,479
5.1%
1,555
5.1%
in %
Technical
Non-technical
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
Gross generation GPL system
GWh
1,107
1,166
1,229
1,295
1,364
1,438
1,516
1,599
1,686
1,779
1,876
1,972
2,073
2,178
Linden Power Company
GWh
100
103
106
109
112
116
119
123
127
131
135
139
143
147
Self generation switching to the grid
GWh
Total expected demand
Expected demand growth
GWh
%
Average load
Peak demand
MW
MW
166
1,373
4.9%
157
227
171
1,440
4.9%
164
238
176
1,511
4.9%
182
1,585
4.9%
172
250
181
262
187
1,664
5.0%
193
1,747
5.0%
190
275
199
1,835
5.0%
205
1,927
5.0%
211
2,024
5.1%
218
2,127
5.1%
225
2,236
5.1%
232
2,342
4.8%
239
2,454
4.8%
246
2,571
4.8%
199
289
209
304
220
319
231
335
243
352
255
370
267
388
280
406
294
425
GENERATION BALANCE - WITHOUT INCLUDING AMAILA AMONG SELECTED PROJECT CANDIDATES TO EXPAND THE SYSTEM
DISPATCH OF POWER PLANTS:
Exisiting Thermal Power Plants
Guysuco Cogenerator (PPA)
New Thermal Facilities
Total Generation
GWh
GWh
GWh
GWh
436
81
856
1,373
429
81
931
1,440
425
81
1,005
1,511
388
81
1,117
1,585
392
81
1,191
1,664
363
81
1,303
1,747
339
81
1,414
1,835
357
81
1,489
1,927
343
81
1,601
2,024
297
81
1,749
2,127
294
81
1,861
2,236
289
81
1,973
2,342
252
81
2,122
2,454
220
81
2,270
2,571
MW
MW
MW
272
14
286
286
14
300
300
14
314
314
21
335
335
14
349
349
21
370
370
21
391
391
14
405
405
21
426
426
28
454
454
21
475
475
21
496
496
28
524
524
28
552
%
26%
26%
26%
28%
27%
28%
29%
27%
27%
29%
28%
28%
29%
30%
GENERATION CAPACITY:
Existing thermal
Annual Thermal new additions
Total Installed Capacity
Reserve margin (Installed Capacity /
Peak demand)
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
69
Simulation Model output: Generation balance without including Amaila Falls among selected candidates
Period 2037 - 2050
SIMULATION MODEL OUTPUT (GENERATION BALANCE) - Option without including Amaila Falls among selected candidates
ASSUMPTIONS - Base Case
Demand Forecast
Total Sales GPL system
T & D losses
Year
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
GWh
annual growth
1,635
5.1%
1,719
5.1%
1,808
5.1%
1,901
5.1%
1,999
5.1%
2,102
5.1%
2,210
5.1%
2,324
5.1%
2,443
5.1%
2,569
5.1%
2,701
5.1%
2,840
5.1%
2,986
5.1%
3,140
5.1%
in %
Technical
Non-technical
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
Gross generation GPL system
GWh
2,290
2,407
2,530
2,659
2,795
2,938
3,088
3,246
3,412
3,587
3,770
3,963
4,166
4,379
Linden Power Company
GWh
151
155
160
164
169
174
179
184
190
195
201
207
213
219
Self generation switching to the grid
GWh
Total expected demand
Expected demand growth
GWh
%
Average load
Peak demand
MW
MW
254
2,694
4.8%
308
446
262
2,824
4.8%
322
467
270
2,959
4.8%
278
3,102
4.8%
338
490
354
513
287
3,251
4.8%
371
538
296
3,408
4.8%
389
564
305
3,572
4.8%
314
3,745
4.8%
324
3,926
4.8%
334
4,116
4.8%
344
4,315
4.8%
355
4,524
4.8%
366
4,744
4.9%
377
4,975
4.9%
408
591
427
620
448
649
470
681
493
714
516
749
542
785
568
823
GENERATION BALANCE - WITHOUT INCLUDING AMAILA AMONG SELECTED PROJECT CANDIDATES TO EXPAND THE SYSTEM
DISPATCH OF POWER PLANTS:
Exisiting Thermal Power Plants
Guysuco Cogenerator (PPA)
New Thermal Facilities
Total Generation
GWh
GWh
GWh
GWh
231
81
2,382
2,694
212
81
2,531
2,824
161
81
2,717
2,959
155
81
2,866
3,102
118
81
3,052
3,251
100
81
3,227
3,408
74
81
3,417
3,572
57
81
3,607
3,745
10
81
3,835
3,926
81
4,035
4,116
81
4,234
4,315
81
4,443
4,524
81
4,663
4,744
81
4,894
4,975
MW
MW
MW
552
21
573
573
28
601
601
35
636
636
28
664
664
35
699
699
35
734
734
35
769
769
35
804
804
42
846
846
42
888
888
42
930
930
42
972
972
49
1,021
1,021
49
1,070
%
29%
29%
30%
29%
30%
30%
30%
30%
30%
30%
30%
30%
GENERATION CAPACITY:
Existing thermal
Annual Thermal new additions
Total Installed Capacity
Reserve margin (Installed Capacity /
Peak demand)
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
30%
30%
70
Simulation Model output: Generation balance including Amaila Falls among selected candidates
Period 2009 - 2022
SIMULATION MODEL OUTPUT (GENERATION BALANCE) - Option including Amaila Falls among selected candidates
ASSUMPTIONS - Base Case
Demand Forecast
Total Sales GPL system
T & D losses
Year
2009
2010
2011
2012
2013
2014
2015
2016
2017
2018
2019
2020
2021
2022
GWh
annual growth
393
418
6.3%
431
3.2%
453
5.0%
476
5.1%
500
5.1%
525
5.1%
552
5.1%
581
5.2%
611
5.2%
643
5.2%
677
5.2%
712
5.3%
750
5.3%
in %
Technical
11.4%
10.6%
9.9%
9.3%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
Non-technical
21.6%
19.4%
17.5%
15.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
949
999
1,052
Gross generation GPL system
GWh
587
597
619
647
673
Linden Power Company
GWh
Self generation switching to the grid
GWh
Total expected demand
Expected demand growth
GWh
%
653
665
1.8%
689
3.6%
719
4.3%
748
4.0%
MW
MW
75
108
76
110
79
114
82
119
85
124
Average load
Peak demand
66
-
68
-
70
-
72
-
74
-
701
737
775
815
857
902
76
79
81
83
86
88
91
94
97
79
131
135
139
143
148
152
157
161
856
14.5%
947
10.6%
991
4.7%
1,037
4.7%
1,086
4.7%
1,138
4.7%
1,192
4.8%
1,249
4.8%
1,310
4.8%
98
142
108
157
113
164
118
172
124
180
130
188
136
197
143
207
149
217
GENERATION BALANCE - WITH AMAILA AMONG SELECTED PROJECT CANDIDATES TO EXPAND THE SYSTEM
DISPATCH OF POWER PLANTS:
Amaila Falls
Exisiting Thermal Power Plants
Guysuco Cogenerator (PPA)
New Thermal Facilities
Total Generation
GENERATION CAPACITY:
Amaila Falls
Existing thermal
Annual Thermal new additions
Total Installed Capacity
Reserve margin (Installed Capacity /
Peak demand)
GWh
GWh
GWh
GWh
GWh
614
39
653
584
81
665
608
81
689
601
81
37
719
629
81
37
748
813
43
856
862
81
4
947
872
81
38
991
892
81
64
1,037
912
81
93
1,086
921
81
135
1,138
930
81
181
1,192
949
81
219
1,249
983
81
246
1,310
MW
MW
MW
143
143
147
147
139
139
135
7
142
132
132
148
132
280
148
132
280
148
132
280
148
132
280
148
132
280
148
132
280
148
132
280
148
132
280
148
132
280
%
32%
34%
22%
19%
92%
74%
66%
59%
52%
45%
38%
32%
26%
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
7%
71
Simulation Model output: Generation balance including Amaila Falls among selected candidates
Period 2023 - 2036
SIMULATION MODEL OUTPUT (GENERATION BALANCE) - Option including Amaila Falls among selected candidates
ASSUMPTIONS - Base Case
Demand Forecast
Total Sales GPL system
T & D losses
Year
2023
2024
2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
GWh
annual growth
790
5.3%
832
5.3%
876
5.3%
923
5.4%
973
5.4%
1,025
5.4%
1,081
5.4%
1,140
5.5%
1,202
5.5%
1,268
5.5%
1,338
5.5%
1,407
5.1%
1,479
5.1%
1,555
5.1%
in %
Technical
Non-technical
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
Gross generation GPL system
GWh
1,107
1,166
1,229
1,295
1,364
1,438
1,516
1,599
1,686
1,779
1,876
1,972
2,073
2,178
Linden Power Company
GWh
100
103
106
109
112
116
119
123
127
131
135
139
143
147
Self generation switching to the grid
GWh
Total expected demand
Expected demand growth
GWh
%
Average load
Peak demand
MW
MW
166
1,373
4.9%
157
227
171
1,440
4.9%
164
238
176
1,511
4.9%
182
1,585
4.9%
172
250
181
262
187
1,664
5.0%
193
1,747
5.0%
199
1,835
5.0%
205
1,927
5.0%
211
2,024
5.1%
218
2,127
5.1%
225
2,236
5.1%
232
2,342
4.8%
239
2,454
4.8%
246
2,571
4.8%
190
275
199
289
209
304
220
319
231
335
243
352
255
370
267
388
280
406
294
425
GENERATION BALANCE - WITH AMAILA AMONG SELECTED PROJECT CANDIDATES TO EXPAND THE SYSTEM
DISPATCH OF POWER PLANTS:
Amaila Falls
Exisiting Thermal Power Plants
Guysuco Cogenerator (PPA)
New Thermal Facilities
Total Generation
GENERATION CAPACITY:
Amaila Falls
Existing thermal
Annual Thermal new additions
Total Installed Capacity
Reserve margin (Installed Capacity /
Peak demand)
GWh
GWh
GWh
GWh
GWh
983
81
309
1,373
983
81
376
1,440
983
81
447
1,511
983
81
521
1,585
983
81
600
1,664
983
81
683
1,747
983
81
771
1,835
983
81
863
1,927
983
81
960
2,024
983
81
1,063
2,127
983
81
1,172
2,236
983
81
1,278
2,342
983
81
1,390
2,454
983
81
1,507
2,571
MW
MW
MW
148
132
14
294
148
146
14
308
148
160
14
322
148
174
21
343
148
195
14
357
148
209
21
378
148
230
21
399
148
251
14
413
148
265
21
434
148
286
28
462
148
314
21
483
148
335
21
504
148
356
28
532
148
384
28
560
%
26%
26%
26%
28%
27%
28%
29%
27%
27%
29%
28%
28%
29%
30%
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
72
Simulation Model output: Generation balance including Amaila Falls among selected candidates
Period 2037 – 2050
SIMULATION MODEL OUTPUT (GENERATION BALANCE) - Option including Amaila Falls among selected candidates
ASSUMPTIONS - Base Case
Demand Forecast
Total Sales GPL system
T & D losses
Year
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050
GWh
annual growth
1,635
5.1%
1,719
5.1%
1,808
5.1%
1,901
5.1%
1,999
5.1%
2,102
5.1%
2,210
5.1%
2,324
5.1%
2,443
5.1%
2,569
5.1%
2,701
5.1%
2,840
5.1%
2,986
5.1%
3,140
5.1%
in %
Technical
Non-technical
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
8.1%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
12.7%
Gross generation GPL system
GWh
2,290
2,407
2,530
2,659
2,795
2,938
3,088
3,246
3,412
3,587
3,770
3,963
4,166
4,379
Linden Power Company
GWh
151
155
160
164
169
174
179
184
190
195
201
207
213
219
Self generation switching to the grid
GWh
Total expected demand
Expected demand growth
GWh
%
Average load
Peak demand
MW
MW
254
2,694
4.8%
308
446
262
2,824
4.8%
322
467
270
2,959
4.8%
278
3,102
4.8%
338
490
354
513
287
3,251
4.8%
296
3,408
4.8%
305
3,572
4.8%
314
3,745
4.8%
324
3,926
4.8%
334
4,116
4.8%
344
4,315
4.8%
355
4,524
4.8%
366
4,744
4.9%
377
4,975
4.9%
371
538
389
564
408
591
427
620
448
649
470
681
493
714
516
749
542
785
568
823
GENERATION BALANCE - WITH AMAILA AMONG SELECTED PROJECT CANDIDATES TO EXPAND THE SYSTEM
DISPATCH OF POWER PLANTS:
Amaila Falls
Exisiting Thermal Power Plants
Guysuco Cogenerator (PPA)
New Thermal Facilities
Total Generation
GENERATION CAPACITY:
Amaila Falls
Existing thermal
Annual Thermal new additions
Total Installed Capacity
Reserve margin (Installed Capacity /
Peak demand)
GWh
GWh
GWh
GWh
GWh
983
81
1,630
2,694
983
81
1,760
2,824
983
81
1,895
2,959
983
81
2,038
3,102
983
81
2,187
3,251
983
81
2,344
3,408
983
81
2,508
3,572
983
81
2,681
3,745
983
81
2,862
3,926
983
81
3,052
4,116
983
81
3,251
4,315
983
81
3,460
4,524
983
81
3,680
4,744
983
81
3,911
4,975
MW
MW
MW
148
412
21
581
148
433
28
609
148
461
35
644
148
496
28
672
148
524
35
707
148
559
35
742
148
594
35
777
148
629
35
812
148
664
42
854
148
706
42
896
148
748
42
938
148
790
42
980
148
832
49
1,029
148
881
49
1,078
%
29%
29%
30%
29%
30%
30%
30%
30%
30%
30%
30%
30%
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
30%
30%
73
ANNEX II – SELF GENERATORS SURVEY
(Prepared by Mr. John Cush, local consultant retained by GPL)
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
74
JOHN A. CUSH, FGAPE, MIEEE, MAWWA
20 Dandrade Street, Newtown
Kitty, Georgetown.
Tel./Fax: 592-225-2640 / 592-645-9923; e-mail: [email protected]
November 17, 2009
Mr. W. Brassington
Executive Director,
National Industrial and Commercial
Investments Ltd (NICIL),
126, Barrack Street,
Kinston,
Georgetown.
Dear Mr. Brassington,
RE: Self Generation Survey; - Final Report.
Enclosed please find completed Final Report and Questionnaires for the above
captioned.
The report covers the Consultants findings during the survey period. As
indicated in the report a number of barriers were encountered when conducting
the Telephone survey. This no doubt contributed the Consultants inability to
survey greater a number of the “small scale” user.
I do hope you find this report satisfactory and should you require any
clarification on any part of its contents please do not hesitate to contact me.
Best regards.
Yours sincerely
John A. Cush
Electrical Engineer
Cc: Mr. M. Sharma – CEO (ag) GEA.
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
75
SUMMARY
This report seeks to present the findings of the Self-Generation (SG) Survey conducted
by John A. Cush, Electrical Engineer there after referred to as the Consultant.
The Consultant has been engaged by National Investment and Commercial Investments
Ltd (NICIL) and the Guyana Power and Light Inc (GPL) to conduct a survey to verify the
level of self generation presently employed in Guyana, given the fact that every person
has the right to self generate.
The methodology used to execute the survey was to:
•
Review the database supplied by the GEA with the intention to identify the Top
Twenty listed organisations
•
Conduct site visits to the various operations at which self generation is
predominant. That is mainly the so called “Top Twenty” industrial / commercial
organisations which are self generating.
•
Conduct telephone interviews with other individuals and organisations listed in
the database to verify the accuracy of the data.
A specific set of questions were asked of the various operators relating to their
generating activities. See questionnaire appended.
OBJECTIVES
The objective of the Survey is to;
•
Conduct a field verification of the SG database obtained from the Office of the
Prime Minister
•
Update the said database
•
Establish the level of SG that is taking place.
PROJECT CONCEPT.
The Government of Guyana’s policy is that every person has the right to self generate.
Therefore SG is allowed with no restrictions as far as all power is used for self
consumption.
Most of the SG organisations are industrial / manufacturing operations and units are
usually matched to produce the power needs of the particular operation.
As project planning of the Amaila Falls Hydroelectric plant progress it has become
evident that there needs to be a through appreciation of the level of self generation
which occurs. It is also necessary to know the total installed capacity and energy
demand of the self generators.
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
76
SURVEY RESULTS.
The results of the survey to date indicate that most of the major manufacturing
operations use their generators as a main power source.
The main objective of implementing self generating facilities is to reduce cost related to
energy resources and to overcome the frequent power outages.
The results show that presently some 10.94 GWh is produced monthly by individual self
generators. See appendix 2. This translates into annual generation of 131.28 GWh per
year. This is a significant amount of energy.
Self generation is mostly being used to secure reliable supply as a result of the inability
of the GPL to supply and in some cases to reduce the cost of power during peak
production hours.
There are two clear groups of operators with GPL connections. The first group only use
the GPL supply as a back up to their main source of supply and the second group
obtains all or nearly all of their supply from GPL.
The table appended deals strictly with operators who self generate either twenty four /
seven (24/7) or those whom generate during the production cycle.
The majority of the self generators are located along the East Bank of Demerara corridor
which is an area in close proximity with the existing GPL grid. However as mentioned
earlier most operators are off grid due to unreliability of power supply.
A number of these operators have however expressed a desire to be reconnected on the
GPL grid.
The total installed capacity of the thirty six(36) listed companies is 59,933.7 kVA. Of the
listed operators surveyed only two have indicated use of machines as standby units,
meaning that they only use them in cases of emergency. All others utilise their machines
as load demand necessitates. Thus in some cases all machines will be running or a
combination of machines will be used.
Further analysis of the installed capacity gives the following break down. See below
table.
Sector
Fisheries
Brewery/Distilleries
Manufacturing
Wood Products
Hospitality
Industrial- Metals
Industrial – Gas
bottling
Number of
Companies
7
2
9
4
4
5
Installed
Capacity (kVA)
17,060
12,344
15,308
4,243.5
2,265
Percent of
Total
29.2
21.68
26.2
8.14
7.26
3.88
1
1,000
1.71
4,755.5
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
77
Shipping
Retail operations
Services
Totals:
1
1
2
750
464
243.7
1.28
0.79
0.42
36
58,433.7
100.0
The above table reveals that the manufacturing sector has the most self generators of
the firms surveyed while the fisheries sector has the largest installed capacity. The
Services has the least installed capacity. The table also shows that the fisheries,
brewery/distilleries and manufacturing sectors account for the largest percentage of self
generators. That is 44,712 kVA or 76 percent of the installed capacity.
It is reported that the GPL has a total installed capacity of 125 MW. However within the
thirty six (36) companies there are ninety four (94) individual generating units installed
which have a combined total of 58,433.7 kVA or approximately 47 MW13. This is a
significant amount of power since it is approximately 38 percent of the GPL installed
capacity.
The table below ranks the individual companies with respect to their installed capacity.
Name of Company
Installed Capacity (kVA)
Demerara Distilleries Ltd.
Prittipaul Investments
Noble House
Banks DIH
Caribbean Containers Ltd
Guyana Stockfeeds Ltd.
Bev Enterprise
Guyana Quality Sea
Foods
Sterling Products Ltd
Barama
Pegasus Hotel
Edward Beharry & Co Ltd
Buddy’s Princess Hotel
Continental Industries
E.C. Viera Investments
BM Enterprise
8150
5,010
4,625
4,194
4,050
3,920
3,100
3,000
Percentage (%) of
Installed Capacity
13.95
8.57
7.91
7.18
6.93
6.71
5.31
5.13
2,956
2,587.5
2,012.5
1890
1,876
1,300
1290
1025
5.06
4.43
3.44
3.23
3.21
2.22
2.21
1.75
13
Converted using a power factor of 0.8.
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
78
Name of Company
Demerara Oxygen
Guyana Furniture
Manufacturing
Precision Woodworking
John Fernandes Ltd.
Trinidad Cement Ltd.
(TCL)
Industrial Fabrication Ltd.
Giftland Office Max
Triple Star Enterprises
Parika Sawmills
Popeyes Restaurant
Caribbean Aviation
Maintenance Services
BASIF
ECI
Marlin Inc.
Technical Services Inc.
Supra International Inc.
Single Seafood
Loring Laboratories
Namilco
Germans Restaurant
TOTALS:
Installed Capacity (kVA)
1000
965
Percentage (%) of
Installed Capacity
1.71
1.65
890
750
622
1.52
1.28
1.06
500
464
360
313
300
168.7
0.86
0.79
0.62
0.54
0.51
0.29
165
160
160
150
150
140
75
60
55
58,433.7
0.28
0.27
0.27
0.26
0.26
0.24
0.13
0.10
0.09
100..0
The table shows that thirteen (13) companies account for approximately 80 percent of
the installed capacity of which one (1) company alone accounts for approximately
fourteen (14) percent.
The graph below show the grouping of the generators within the various sizes. The
generators were grouped from under 100 kVA to over 900 kVA. The results show that
out of the ninety (94) generators in excess of twenty five (25) are rated over 900 kVA.
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
79
Installed kVA Rating of Major Self Generators
Installed kVA
800 - 900
600 - 699
400 - 499
200 - 299
Under 100
0
5
10
15
20
25
30
Num ber of Generators
The hours of operation varies between company to company. This is because some
companies run their generators twenty four hours a day seven days a week (24/7) while
others just run the generators during production hours.
The chart below shows that 16 percent of the companies run their generators for a
period of 160 hours within a given month while 31 percent run their generators for 720
hours within the month.
Monthly Generation Hours
16%
27%
0 - 160
161 - 320
321 - 480
481 - 640
4%
31%
641 - 800
22%
Average monthly fuel consumption varies significantly between the groups surveyed.
Four (4) companies offered not to give any response to this particular request. Despite
repeated request. Most companies reported using diesel fuel while only one company
utilise heavy fuel oil. The Consultant also believes that there are significant errors in the
reported fuel figures since most of the person who where answering the question were
not quite certain as to the fuel consumptions. As a result the energy/ fuel ratio ( kWh/
gal) reported may not be a true representation of generator performance.
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
80
Load supplied (reported) represents the load figures reported by the companies. As
seen in the appended spread sheet some companies reported the load in various
manners. Some reported in Amperes, kVA or kW. Also the majority of the figures given
were average figures.
The calculated14 load column shows the values computed taking into account the
operating voltage of the various operations. In cases where the load value was given by
the company that figure was used. For example the load reported by Precision
woodworking is 350 kW thus this value was transferred into the calculated column.
A similar situation exists with the reported energy consumption. Of the thirty six
companies surveyed only four (4) of them have reported recording energy consumption.
And as may be expected they are some of the major self generators. Those companies
are DDL, Banks DIH, Caribbean Containers and Barama. However it has been noticed
that there is a significant variation between the calculated energy consumption and the
reported values.
As a result of this discrepancy the Total Energy Generated varies between 10.94 GWh
using calculated values or10.66 GWh using the reported figures in the computation of
the total energy consumption.
TELEPHONE SURVEY.
The database used to conduct the entire survey contained some six hundred and twenty
two (622) entries. Where each entry can be treated as equal to a generator. However in
some cases it was found that for some entries the kVA rating consisted of the sum of a
number of generating units.
The Consultant was subsequently informed by staff from the Office of the Prime Minister
that a waiver had been granted by the Prime Minister for the non-registration of
generators rated less than 10 kVA. Taking this into consideration the original listing was
then sorted by kVA rating in descending order.
The sorted list produced 434 entries greater than 10 kVA out of the 622 entries. This
then means there are some 188 entries between 0.1 and 9.9 kVA.
In analysing the over 10kVA grouping it was found that approximately 20 percent self
generate while the others used their units as a standby source.
It was also found that there are a number of companies which have more than three (3) entries in the
database. The companies found with multiple entries are;
Power (Kw) = √3*V*I*pf; where V=voltage, I= amperes, pf =power factor. For 3phase operating
systems. And P= V*I*pf for single phase systems.
14
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
81
Company
Listed Number
Duty Run
Corrected number
Guyana Telephone and
123
4
123
Banks DIH
21
3
14
Republic Bank
16
0
15
Edward Beharry & Co.
13
5
13
Delegation of European
12
0
11
9
0
6
194
12
182
Telegraph Co.
Commission
Gafsons
Totals:
The listed total in the above table represents approximately 45 percent of the over
10kVA generator population. However it should be noted of the 194 sets within the listed
firms only12 or 6 percent of the units perform as duty sets apart from those mentioned
earlier in this report.
Also coming to light was that a number of units listed under these organisations are no
longer in operation or have been replaced. Hence for the group listed in the above table
the corrected numbers are 182 or 42 percent of the over 10 kVA group.
There were also cases of duplicated entries.
Apart from companies and organisations telephone verification was also sought from
apparent listed individuals who have units registered. It should also be mentioned that
during the telephone survey it was found that there are a number of so called “small” self
generators. These are companies with less than 1 percent of the total installed capacity
as shown in table 2 above.
During the course of the survey a number of barriers were confronted. They are:
¾ Reluctance of some person to respond
¾ Unavailability of telephone numbers ( no listing, etc)
¾ Persons at home but cannot give details about the generator
CONCLUSION
The survey revealed the following;
‰
All companies surveyed are within grid areas
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82
‰
Monthly self generation estimated at 10.94 GWh
‰
Self generation installed capacity is in excess of 47MW or 38 percent of GPL
installed capacity.
‰
Self generation is mostly used to secure reliable power supply
‰
There are a number of firms which are interested in having GPL connections.
‰
There are two clear groups of operators with GPL connections. The first group
only use the GPL supply as a back up to their main source of supply and the
second group obtains all or nearly all of their supply from GPL.
‰
A number of firms will like to see the cost of power reduced and reliability and
quality improved.
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ANNEX I. SAMPLE QUESTIONAIRE.
SELF GENERATION QUESTIONAIRE
______________
Name of Company: ……………………………………………….…...
Company Address: ……………………………………………………..
Company Representative: …………………………………………………
Contact Number: ………………………………
1. How many generators does the company have? : ……………..
2. What is the rating (kVA) of the generator? : ………………………………..
3. Is Generator used as Main source of Power or Standby? : ………………………
4. What are the hours of operation per month? ……………..
5. What is the average monthly fuel consumption? : …………………….
6. What is the type of fuel used?: ………………………………
7. What is the Load supplied (kVA) ? : ……………………
8. What is the Energy Generated per month (kWh)? : ………………………
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Comments:
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85
ANNEX III – REVIEW OF EXISTING HYDROLOGY STUDIES
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86
1. EXECUTIVE SUMMARY
The design of Amaila Falls Project encountered several problems arising from the lack
of hydrologic data. Therefore, the best techniques available were applied to cope with
the lack of information but even so, several questions remained unanswered, such as
the following:
• The flows used were obtained by extrapolating the results from Kaieter Falls
Station with different transfer coefficients and then adopting 0.30 without further
justification. This may cause some uncertainty regarding the expected power
generation.
• The maximum flow adopted to design the dam was the result of transforming the
Probable Maximum Precipitation value into the Probable Maximum Flow by
adopting a C coefficient (Creaguer’s formula) that has no direct justification, thus
causing uncertainty as regards the maximum flow adopted for the design at 5.010
m3/s.
• In addition, the Probable Maximum Flood was assessed in the current basin
status, with no deforestation or mining exploitation. Any modification of the basin
in such respect will have an impact on the increase in the maximum value
considered.
• The flows assumed for different return periods, which set the maximum values to
be adopted during the construction period, also include coefficients and
parameters adopted without any actual data on the site.
• In order to obtain more accurate information, it would be desirable to install a
hydro-meteorological station in a section of the river that is representative of the
Project. Even if the works start soon, the information obtained will always be
useful and will allow future adjustment of the parameters necessary for operation.
With respect to the studies conducted on the behavior of generation with different dam
heights and installed capacities, it was concluded that:
• Energy production is marked by hydraulicity in the different months of the year. In
wet months (June to September), more power can be generated and demand is
covered.
• In months with low hydraulicity, demand is only partially covered.
• The above shows the reservoir’s poor regulation, considering that in wet months
or periods the surplus flows will be spilled.
• As the reservoir level is increased (more regulation) or installed capacity is
reduced, the percentage of demand coverage grows for the same load factor.
• In the actual case, 140 MW at delivery point and maximum reservoir level at
462.00 m.a.s.l., the trend is confirmed: even with smaller load factors, there is a
deficit in power generation in months with low hydraulicity.
The potential increase in dam height will have little influence on the installed capacity
due to the great existing fall, although it will improve annual power generation,
considering the greater regulation capacity and the following features:
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87
• The increase in the maximum level from 462 to 468 m represents an increase of
26 % in the maximum height of Amaila Dam and 30 % in Kuribrong Dam, with
major economic implications.
• In addition to more investment, other aspects linked to the larger flooded area
should be considered, in particular, associated environmental aspects.
• Another alternative to enhance the dam’s regulation capacity, and therefore its
annual average energy, could be the implementation of circular sector gates
allowing some of the flows in wet months to be stored, thus reducing spilling.
• It is considered, however, that this additional regulation capacity would be limited
and equal to approximately only 10% of the annual spilling.
• The convenience of installing gates to reduce the expected investment remains
to be considered.
2. INTRODUCTION
The review of hydrology studies included the following documents submitted by the
Client:
• Amaila Falls Hydroelectric Project – Guyana - Feasibility Study Report –
Hydrology - Prepared by MWH – December 2001
• Amaila Falls Hydro - Estimated Monthly Energy and Average Power for a Range
of Load Factors – Prepared by MWH – August 2009
• GEOTECHNICAL BASELINE REPORT FOR BIDDING Hydroelectric Power Project – Generating Facilities - June 2008
Amaila
Falls
• Amaila Falls Hydroelctric Project – Generating Facilities – Section 8 – Owners
Requirement Drawings – June 2008
• PPA multiscenarioCovermemo_20090820.pdf
3. PROJECT DESCRIPTION
Amaila Falls project is a conventional hydroelectric project, and the scheme includes
two main dams located upstream of the confluence of the Kuribrong and Amaila Rivers,
just above Amaila Falls. A 3 km long water conductor will divert approximately 50 m3 /
sec of stream flow to the powerhouse, utilizing the available gross head of
approximately 360 meters for electricity production. The proposed installed capacity is
nominally 156 MW with four Francis units. At the normal maximum operating level of
El. 462.0 meters, the storage reservoir would cover an estimated area of 26.7 square
kilometers.
The reservoir would contain a total storage volume of 180 million cubic meters (mcm),
and of this total, 146 mcm would be considered usable for seasonal regulation and
production of firm energy during the drier months. Operation to provide a reliable power
source during the drier months will require a drawdown of the reservoir water level by a
depth of up to 9.5 meters each year, followed by a refill in the subsequent wet months.
The following major components are included in the Project:
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88
• Completion of access roads to the site,
• Bridge across the Kuribrong River,
• Two concrete-faced rockfill dams (CFRD),
• A roller compacted concrete (RCC) overflow spillway, concrete stilling basin, and
spillway channel
• Intake structure and headrace tunnel,
• Surge and power shafts,
• Power tunnel (alternatively, a lower headrace tunnel and surface penstock)
• Powerhouse with electrical and mechanical equipment,
• Tailrace channel,
• Switchyard with transformers and substation, and
• Transmission line from the powerhouse to Linden and Georgetown.
4.
SUMMARY OF KEY PROJECT FEATURES
A brief summary of the key project features follows.
4.1.
DAMS AND SPILLWAY
Two dams are proposed for the Project, the Amaila dam and Kuribrong dam. An 850meter-long ridge connecting the Amaila and Kuribrong dams and has ground surface
elevations varying from about El. 464 to El. 467 meters. Due to the maximum level of
the reservoir of El. 464.8 meters, the ridge will require foundation treatment (i.e.
grouting). As such, the ridge dam section will include low CFRD dams or a modified
parapet wall.
4.1.1.
AMAILA DAM
The Amaila dam is located on the Amaila River approximately 250 meters upstream of
the confluence with the Kuribrong River. The dam will be a concrete-faced rockfill dam
(CFRD), is approximately 950 meters long (including the spillway), and has a maximum
height of approximately 25 meters. A 2- meter-high parapet wall will be installed on the
upstream side of the crest, which is 8-meters-wide and will serve as a two-lane access
road.
An overflow spillway will be constructed within the Amaila dam and will be constructed
with RCC.
The spillway is 237 meters long and has a crest elevation of 462 meters and maximum
height of about 23 meters. The upstream face is sloped at 0.3H:1.0V
(horizontal:vertical) and the stepped downstream face is sloped at 0.8H:1.0V. The
downstream face transitions into a 40-meter-long stilling basin and is then channeled
back into the Amaila River channel. The spillway includes a 4-meter-wide bridge deck
supported on piers.
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4.1.2.
KURIBRONG DAM
The Kuribrong dam is located on the Kuribrong River approximately 1.5 kilometers
upstream of the confluence with the Amaila River. The CFRD, is approximately 850
meters long, and has a maximum height of approximately 20 meters. A 2-meter-high
parapet wall will be installed on the upstream side of the crest, which is 8-meters-wide
and will serve as a two-lane access road.
4.2.
INTAKE AND HEADRACE TUNNEL
The intake structure is located approximately 120 meters upstream of the left abutment
of the Amaila dam. The intake consists of a 145-meter-long approach channel, flared
inlet, and gate structure. The gate structure is 20 meters high constructed of reinforced
concrete, and is equipped with a trash rack, trash rake, hydraulic intake gate, and a
stoplog.
It is presumed that the intake
tunnel. The headrace tunnel
tunnel and sloped toward the
supported with a combination
sets. The tunnel will be lined
conditions encountered.
4.3.
will be used as a portal for constructing the headrace
is a 1,600-meter-long and 4.7-meter-wide D-shaped
powerhouse at about 1.5 percent. The tunnel will be
of reinforced shotcrete, rockbolts, concrete, and steel
with shotcrete of concrete depending on the geologic
SURGE AND POWER SHAFT
A 7.0-meter-diameter surge shaft will be excavated from the ground surface to the
headrace tunnel.
The shaft will be supported near the surface with a shaft collar and with systematic
rockbolts and reinforced shotcrete below. The surge shaft includes a 50-centimeterthick concrete lining. A 20-meter-high above-grade surge tank will aid in system
governing.
A 4.1-meter diameter power shaft will extend below the headrace tunnel to the
minimum invert elevation of El. 110 meters. The shaft will be supported with systematic
rockbolts and shotcrete.
The surge shaft will have a 30-centimeter-thick concrete lining.
Alternatively, the power shaft will extend to about El. 345 meters, and connect to a
short lower headrace tunnel segment.
4.4.
POWER TUNNEL
The power tunnel is a 1,230-meter-long and 4.7-meter-wide D-shaped tunnel. In the
lowest acceptable water conductor profile, the power tunnel extends from the base of
the vertical power shaft at minimum El. 110 meters to the bifurcation at the powerhouse
at a slope of approximately 1.5 percent.
The tunnel will be supported with a combination of shotcrete, rockbolts, concrete, and
steel sets. The tunnel will be finished to a circular cast-in-place concrete-lining or steellining with concrete backfill section.
4.5.
LOWER HEADRACE TUNNEL AND SURFACE PENSTOCK ALTERNATIVE
A lower headrace tunnel and surface (buried) penstock, is an alternative water
conductor connecting the power shaft to the powerhouse represents the highest
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90
acceptable water conductor profile. The lower headrace tunnel is a 300-meter-long and
4.7-meter-wide D-shaped tunnel extending from the power shaft at about El. 345 to a
portal below the face of the escarpment.
The tunnel will be supported with a combination of reinforced shotcrete, rockbolts,
concrete, and steel sets. The finished tunnel will be circular and be concrete-lined or
steel-lined with concrete backfill.
The cut-and-cover steel penstock is approximately 1,040 lineal meters and has an
inside diameter of approximately 3.1 meters. The penstock pipe will be constructed in
an open-cut earth or rock trench or supported on compacted rock fill, installed on a
layer of bedding material, and buried with compacted sand and rockfill. Anchor and
thrust blocks will be needed at locations where there are significant changes in the
vertical or horizontal alignment.
4.6.
POWERHOUSE
The powerhouse is located in an area along the left bank of the Kuribrong River in
which it is expected that the powerhouse will be founded entirely on sound rock.
The partially buried powerhouse will be an enclosed structure with a reinforced mass
concrete substructure, steel and concrete superstructure, and a sloping, trusssupported roof. The powerhouse is approximately 27-meters-wide by 51-meters-long,
with a maximum height of about 34 meters.
Each of the four units has an installed capacity of 39 MW.
4.7.
TAILRACE CHANNEL
The tailrace channel is 36 meters-wide at the base, 110-meters-long, and has a
maximum depth of 13 meters. It will be excavated through overburden and boulders
and bedrock before connecting to the Kuribrong River. The channel will be both unlined
and lined with concrete and rip rap, to a finished elevation of approximately 96 meters.
4.8.
SWITCHYARD
The switchyard will be constructed immediately northwest of the powerhouse. The
electrical substation will be constructed on the pad having a finished elevation of 108
meters and connect to the transmission line. The switchyard pad will be constructed on
bedrock and compacted rock fill and is approximately 75 meters wide and long.
4.9.
KURIBRONG BRIDGE
The Kuribrong Bridge is located approximately 100 meters downstream of the
powerhouse and will serve as a permanent access to the powerhouse area. The bridge
is approximately 120 meters long and capable of safely transporting the single largest
and heaviest piece of construction or permanent equipment transported on site. The
abutments will be founded on bedrock and have a minimum underside elevation of
108.5 meters.
5. HYDROLOGY ASPECTS
Information on hydrology is the foundation of any hydroelectric project, as it provides
key information for different major aspects of design, economic assessment and
security related aspects such as: design flow for diversion works; mximum flow to be
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
91
controlled by the reservoir and to be released by the spillway; mnimum distribution flow
for environmental requirements; reservoir operation rules; energy that can be
generated for different conditions; reservoir evaporation and reservoir sedimentation.
The reference study to obtain hydrology design parameters for Amaila Falls was
developed by MWH (Montgomery Watson Harza).
The basin contributing to Amaila Falls is defined by those of the Amaila and Kuribrong
Rivers, but no hydrologic information on either river has been collected on site for a
considerable period of time (1979-1989).
Therefore, some important office work has been performed by using the information
available, and this has helped to generate the hydrology to be used in the project.
5.1.
SITUATION OF AMAILA PROJECT
The hydrology situation of Amaila Falls was analyzed from the existing information in
the document prepared by MWH.
The Amaila Dam is located in the central western part of Guyana, immediately
upstream of the confluence of the Kuribrong and Amaila Rivers.
After receiving the contribution of the Amaila River, the Kuribrong River flows west for
about 90 km and joins the Potaro River, downstream of Kaieteur Falls. The Potaro
River, on the other hand, joins the Essequibo some 30 km downstream of its
confluence with the Kuribrong. The Essequibo flows north into the Atlantic Ocean 35
km northwest of the country’s capital city, Georgetown.
5.2.
TOPOGRAPHY AND CONTRIBUTING BASINS DRAINAGE
The total area of the Amaila and Kuribrong Rivers contributing basins is 648 Km2,
119.4 Km2 of which correspond to the Amaila River. In the confluence area, vegetation
is very thick and generates strong resistance to runoff.
The Kuribrong River starts at 670 m.a.s.l., runs southwest for 21 Km, and then turns
north. The total slope of the river until reaching the foot of the dam is 350 m. The river’s
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92
longitudinal slope is 2.42 m/Km up to 50 Km upstream of the dam whereas at the head
the slope is 0.73 m/Km.
As for the Amaila River, it starts at 610 m.a.s.l. and flows east to the confluence with
the Kuribrong. The bottom slope in the dam area is 2.56 m/Km whereas at the head the
slope is 38.1m/Km.
6. OBTAINING THE RESERVOIR’S HYDROLOGY PARAMETERS
6.1.
DETERMINATION OF AVERAGE MONTHLY AND ANNUAL FLOWS
The annual periods surveyed were analyzed with data from the gauging stations in the
area; their proximity was also examined in connection with the location chosen for the
projected dam.
Thus, the station on the Potaro River near Kaieteur Fall was selected as the most
representative. It has a 41-year record of average daily flows (1950-1990) with some
information gaps between 1979 and 1989. The basin’s drainage area at the control
point is 2797 m2. These recorded average daily flows helped to obtain the average
monthly and annual flows – both maximum and minimum - in that station.
By means of statistical inference and the use of the HEC-4 program (US Army), the
missing data series between 1979 and 1989 was completed.
Since the gauging results were obtained at the Potaro River, it was necessary to
extrapolate them by means of coefficient 0.3 to transfer them to the dam’s location.
The coefficient was obtained from data on the Kuribrong River and results were
compared with the data from the gauging station on the Potaro from December 2000 to
August 30, 2001.
An average value of 0.352, with a minimum of 0.182 and a maximum of 1.825, was
obtained from the relation between the flows surveyed on the Kuribrong River and the
hydro-meteorological data measured at the station on the Potaro in the surveyed
period.
A gauging study conducted on the Kuribrong River in June-July 1975 was considered
as background information. There were 22 measurements which resulted in an
average relation between flows of 0.30. The use of a value of 0.26 was suggested,
considering the thicker vegetation on the Kuribrong River basin and an area relation of
0.23 between basins.
A value of 0.30 was used as transposition factor for this study. It was deemed
adequate considering the results obtained. This factor was applied on the hydrometeorological flows measured on the Potaro River near Kaieteur Fall.
By means of this procedure, an estimated average flow of 64.1 m3/s was obtained;
maximum and minimum flows were estimated at 210.1 m3/s and 4.5 m3/s.
The results are shown in the following graph:
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93
Monthly Streamflow - Kuribrong River downstream to the Amaila falls site
225,0
Monthly Mean Streamflow
Monthly Maximum Streamflow
200,0
Monthly Minimum Streamflow
175,0
Flow
Q [m3/s]
150,0
125,0
100,0
Qm = 64,1 m3/s
75,0
50,0
25,0
Dec
Nov
Oct
Sep
Aug
Jul
Jun
May
Apr
Mar
Feb
Jan
0,0
Month - Period of Record [1950 - 1990]
The following graphs show the probabilities of flows being equal or greater in the
different months surveyed, considering the period between 1950 and 1990.
[January - June] - Percent Time Discharge Equalled or Exceeded - [Períod of Record 1950-1990]
350
January
325
February
300
March
April
275
May
250
June
Flow
Q [m 3/s]
225
200
175
150
125
100
75
50
25
0
0,00
10,00
20,00
30,00
40,00
50,00
60,00
70,00
80,00
90,00
100,00
Percent [ %]
Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
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[July - Dicember] - Percent Time Discharge Equalled or Exceeded - [Períod of Record 1950-1990]
275
July
250
August
September
225
October
November
200
Dicember
Flow
Q [m 3/s]
175
150
125
100
75
50
25
0
0
10
20
30
40
50
60
70
80
90
100
Percent [ %]
6.2.
RESERVOIR EVAPORATION
In order to determine reservoir evaporation, the data obtained from the gauging station
at Kaieteur Fall, with a 17-year record from 1959 to 1975, was considered.
Average gross evaporation in the reservoir was 1546 mm a year. The minimum
monthly value was 63 mm and the maximum was 201 mm.
To obtain net evaporation, reservoir evaporation was considered to be 75% of gross
evaporation and this was compared to the accumulated precipitation for all relevant
months.
The results show an annual net evaporation value of 629 mm.
The graph with the results obtained is shown below:
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Monthly Net Evaporation - Amaila Falls Basin
Annual Net Evaporation = 628 mm
Net Evaporation
120
Lake Evaporation
Evapotranspiration
Evaporation [mm]
100
80
60
40
20
6.3.
Dicember
November
October
September
August
July
June
May
April
March
February
January
0
PROBABLE MAXIMUM FLOW – OPERATION PERIOD
The flow of the probable maximum flood was estimated from the probable maximum
precipitation (PMP). The procedure included an assessment of the following items:
estimation of the PMP; duration of the PMP; temporal distribution of the PMP; losses
due to infiltration; unitary diagram; transformation of PMP into Probable Maximum Flow
and evaluation of the Probable Maximum Flow.
6.3.1.
ESTIMATION OF THE PMP
In order to estimate the PMP value, a method proposed by Hershfield in 1965 was
used, with the following equation:
X m = X n + KmSn
Xm = Maximum Precipitation
Xn = Average Precipitation of annual maximums in a 24-hour series
Sn = Standard Deviation from annual maximums in a 24-hour series
Km = Statistical Variable
The variables in the equation above were estimated by using the data on daily
precipitation obtained from the gauging station at Kaieteur Fall, with a record from 1953
to 1977, and the data from Kamarang station, with a record from 1955 to 2000.
The PMP results for each of these stations were 693 mm and 389 mm. The average of
the two stations, after applying a reduction coefficient of 0.89 for the drainage area,
was therefore considered to be an adequate value. The PMP value was then 481 mm.
6.3.2.
DURATION OF THE PMP
A 24-hour duration was considered adequate, considering topography, slopes, and
rainfall regimes.
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6.3.3.
TEMPORAL DISTRIBUTION OF THE PMP
The temporal distribution of the PMP was based on a study conducted by Persaud and
Forsythe (1980) showing rainfall disaggregation for a Tr = 100 years, for storms lasting
between 5 minutes and 12 hours.
With this data, duration vs. intensity curves were calculated by using the rainfall data
from the Kaieteur Fall station. In order to obtain the disaggregation of the PMP for 24
hours with a 1-hour discretization, disaggregation factors published by the WMO
(World Meteorological Organization) were used. The results are shown below:
Time Distribution of PMP
175
165
150
125
Precipitation [mm/h]
115
100
75
50
40
35
30
20
25
3
3
3
3
3
4
4
5
5
5
1
2
3
4
5
6
7
8
9
10
10
5
5
4
4
3
3
3
18
19
20
21
22
23
24
0
6.3.4.
11
12
13
14
15
16
17
LOSSES DUE TO INFILTRATION
The process of losses due to infiltration can be split into two stages: initial infiltration,
which takes into account vegetation interception, soil depressions, and lack of soil
humidity, and a uniform type of infiltration, which considers the soil’s natural percolation
capacity during storms and after the initial infiltration has taken place.
Considering that the PMP represents the maximum probable precipitation, it seems
adequate to disregard initial losses due to infiltration, whereas in the case of uniform
infiltration, a type C soil (SCS. 1972) was considered, with a value of 3mm/hour.
6.3.5.
UNITARY DIAGRAM
Since two different rivers flow into the site where the dam has been projected, two
different hydrograms apply, pursuant to the characteristics of each basin.
Therefore, the procedure used to define the hydrogram for the Amaila and Kuribrong
Rivers consisted in the transposition of the hydrogram of the Caroni River in
Venezuela, the basin of which is adjacent to that of the Kuribrong. This hydrogram was
obtained in a section with similar characteristics (divided basins).
The base flow was defined as the maximum monthly flow with a value of 219 m3/s,
where 40 m3/s corresponded to the Amaila and 179 m3/s to the Kuribrong, pursuant to
the relation of the contribution areas.
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Unit Hyrograph - Amaila River Subbasin and Kuribrong River Subbasin
10
HU Amaila
HU Kuribrong
Streamflow [m3/s]
8
6
4
2
0
0
1
2
3
4
5
6
7
8
9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36
Hours
6.3.6.
TRANSFORMATION OF PMP INTO PMF
The rainfall-flood transformation was performed by using HEC-1 software, with the
input of the following data: drainage areas in each sub-basin; base flow for each subbasin; PMP with 24-hour duration; temporal distribution of PMP; losses due to
infiltration; percentage of wetlands; unitary hydrogram for each basin.
The hydrology modeling resulted in the composition of the Amaila and Kuribrong Rivers
hydrograms, with a peak flow value of 5010 m3/s and an accumulated volume of de
314 Hm3 after three-day floods.
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6.3.7.
EVALUATION OF THE PMF
Results were evaluated by estimating coefficient C in Creaguer’s formula:
Q = 1.303 C (0.386 A) 0.936 A
−0.048
Where: Q is the peak flow in m3/s and A is the drainage area in Km2. Results show a
value of C = 87, whereas the value of C for the Caroni River in Venezuela was 127.
Past experience shows that the values of C can vary between 80 and 100.
6.3.8.
MAXIMUM DESIGN FLOW DURING THE CONSTRUCTION PERIOD
The values of maximum daily flows were obtained from the data provided by the hydrometeorological station at Kaieteur Fall on the Potaro River from its records between
1950 and 1990, while the missing data was obtained by statistical inference.
The calculation procedure consisted in allocating recurrences from the series of data
obtained and later assigning a probability adjustment curve that can adapt to data
distribution. The distribution curves used were the Generalized Extreme Values curve
and Log Pearson Type III, with adequate adjustment for recurrence periods of less than
50 years in both cases. For longer recurrence periods, the curves showed less
probable values. Therefore, it was necessary to obtain the values of peak flows for the
construction period based on the precipitation data obtained from Kamarang and
Kaieteur meteorological stations.
Once the maximum daily precipitation data had been obtained, the same adjustment
procedure was applied by means of a Log Pearson Type III to obtain the precipitation
values for 2, 5, 10, and 25 years of recurrence by applying the corresponding reduction
coefficients by area, which were 55, 62, and 68%, respectively.
Later, the precipitation to flood transformation was performed by using HEC-1 software,
considering the same input used to calculate the Probable Maximum Flow, except for
the modification in the rainfall data, but with the same rainfall distribution and the same
unitary diagrams.
The results obtained show the peak flow and the accumulated volume for each
recurrence:
Flow
Tr
Precipitation
Peak
Accum. Volume
[year]
[mm]
[m3/sec]
[Hm3]
2 5 10 25 50 100 200 500 1000 97 120 134 153 166 180 194 212 227 708 969 1128 1339 1486 1646 1880 2077 2240 49.1 65.6 75.6 89.1 98.4 108.8 123 136 146.3 Economic and Financial Evaluation Study: Guyana - Amaila Falls Hydro Project
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Flood Peak [Qp] vs Return Period [Tr]
1000
500
2250
200
2000
100
1750
Streamflow [m 3/s]
50
1500
25
1250
10
1000
5
750
2
500
250
Flood Peak vs Tr
0
0
200
400
600
800
1000
Return Period [years]
7. SEDIMENTATION
A sedimentation value of 0.25 mm/year was estimated on the basis of preceding
studies on the Caroni River in Venezuela, near the Kuribrong River basin. Considering
the same sediment transportation for the Kuribrong River, an accumulation of 0.165
Hm3/year was determined, which seems insignificant compared to the estimated
storage capacity of the reservoir: 180 Hm3. This is confirmed when the thick vegetation
in the area is considered, which acts as a green lung to control both surface runoff and
sediment transportation, and the lack of mining exploitation in the analyzed area.
8. CONCLUSIONS ON HYDROLOGY ASPECTS
The hydrology study conducted by MWH for the Amaila Falls Project encountered
several problems arising from the lack of actual information on the project site.
Because of this lack of information, MWH applied the best available techniques,
extrapolating results from similar neighboring basins to fill in the existing information
gaps.
Although the adopted methods are the most adequate and reasonable for this type of
processes marked by the lack of direct hydro-meteorological information, the results
obtained present some uncertainties that are typical of the situation and which may be
summarized as follows:
• There is no hydrologic information available on the section where the Amaila
Dam will be built. The flows considered were obtained by extrapolating the results
from Kaiefeur Fall station, and may cause certain doubts as to the calculated
power generation. The transfer factor was modified at different stages in the
study and reached the value of 0.30 used in 2001. There is not much justification
for this coefficient.
• In this respect, reliable records in Potaro River station cover the period 19501990, as stated in MWH’s report. This does not include the last 19 years.
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• On the other hand, the maximum flow adopted to design the works was
established by transforming the PMP into PMF. Coefficient C is also used for this
transformation, by applying Creaguer’s formula, which has no direct justification
in the analyzed basin. It is even mentioned that the value is 127 for the Caroni
basin, used as a reference due to its proximity to the analyzed basin, whereas
the value adopted for Amaila was 87, and a reasonable value would range
between 80 and 100. This causes uncertainty and may lead to an increase in the
maximum flow adopted for the design at 5,010 m3/s.
• In addition, it should be mentioned that when assessing the PMF, the basin was
considered in its current state, with no deforestation or mining exploitation. Any
modification of the basin in this respect will have an influence on the increase in
the maximum value considered.
• On the other hand, the flows assumed for different return periods, which set the
maximum values to be adopted during the construction period, also include
coefficients and parameters adopted with no actual data on the site, and
introduce certain doubts as to the parameters to be considered during the works.
• It is recommended to set up a hydro-meteorological station in a section of the
river that is representative of the Project, as close as possible to the site, in order
to obtain more accurate information. Even if the works start soon, the information
will always be useful and will allow adjusting hydrology parameters in future.
9. DAM HEIGHT AND INSTALLED CAPACITY
In order to evaluate different alternatives for the height of the dam and its installed
capacity, MWH conducted an evaluation of the monthly energy and average capacity
for a range of load factors from 50 to 100%.
The analysis is based on historical hydrologic data, which indicates the monthly and
annual energy that the Project can generate. To estimate the flows of the Kuribrong
River, the available data on the neighboring basin (Potaro River) was multiplied by a
transposition factor (0.3), as described in the feasibility study.
The hydrology record goes from 1950 to 1990 (41 years of monthly flow data). Current
monthly flow data is not available for analysis.
The data was taken from the report included in the feasibility study for Amaila Falls
Hydroelectric Project from December 2001 (and later update) and is subject to the
limitations described.
Two maximum reservoir levels were considered for the situations described above:
462.0m and 468.0m.
Power generation estimations assume that the power house operates with 96%
availability (the model implies a 4% level for scheduled and forced cutoffs) and is
based on an annual peak of output power depending on the load factor and the given
scenario. The monthly energy demand was evenly distributed in proportion to the
number of days in the month. Power generation is therefore mainly based on demand
requirements, subject to the availability of incoming flows and to the water stored.
9.1.
METHODOLOGY
Reservoir operation was chronologically simulated on a monthly basis for the 492
months in the series as follows:
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• In wet months, the reservoir is filled or remains full and the maximum possible
power is generated until reaching a limit defined as estimated demand, based on
peak capacity for a given load factor. Any extra flow is spilled or (if possible)
stored in the reservoir.
• In dry months, the plant is operated to meet the target demand. Therefore, the
net incoming flow is supplemented by using water from the reservoir to meet
demand until the minimum operation level is reached.
• Different types of hydrology years have been considered pursuant to the
definition of flows in the hydrology report, considering the following:
9.2.
-
Mean years, corresponding to a mean monthly contribution of the
hydrology series considered
-
Minimum hydrology years, corresponding to the minimum monthly
contribution of the hydrology series considered
-
Years exceeded 90% of the time as to the monthly contributions
considered.
RESULTS
The following graphs show the results obtained, based on demand coverage
percentages for the different load factors adopted.
For each of the situations considered, dam height and installed capacity, the graphs
will show the minimum value (that it is exceeded 90% of the time), and the mean value.
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The following conclusions on the behavior of the dam are drawn from the analysis of
the graphs above:
• Energy generation is marked by hydraulicity in the different months of the year. In
wet months (June to September), more power is generated and, in general,
demand is covered.
• On the contrary, in months with low hydraulicity, demand is sometimes only
partially covered.
• This shows little reservoir regulation, considering that in wet months or periods it
has no reservoir capacity and spills surplus flows.
• The design contemplates only one of the 4 cases considered, corresponding to
140 MW supplied capacity and a maximum reservoir level of 462.00 m.
• As usual, it is shown that as the reservoir level increases (more regulation) or
installed capacity decreases, the percentage of demand coverage grows for the
same load factor.
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• In the abovementioned case, corresponding to the actual project, it is confirmed
that, even with lower load factors, there is a deficit in power generation during the
months with the least hydraulicity.
10. POSSIBILITIES OF DESIGN VARIATIONS: GENERAL COMMENTS
The project design has few possibilities of modification, considering that it is based on
all the available information and any possible enhancement should necessarily require
additional field studies.
10.1. INCREASE IN DAM HEIGHT
The increase in dam height is connected with the possibility of generating more power
due to the greater useful head, while enhancing reservoir regulation and reducing the
number of months with energy deficit. Topographical, geotechnical and environmental
conditions could affect the height of the dam, limiting the possibilities of increasing it.
The increase in dam height will not have much incidence on the capacity generated by
the hydroelectric plant, considering that the useful head is about 360 m and any
increase in dam height would only allow for a few more meters of useful head:
• For instance, for every 3.6 m increase in reservoir level, an increase of 1% in
installed capacity would be obtained, which is irrelevant considering hydrology
uncertainties or even transmission losses.
• It should be considered that a 3.6 m increase in the crown level would require a
14.4% increase in the maximum height of the Amaila Dam and an 18% increase
in the maximum height of the Kuribrong Dam. Since the dams have major
longitudinal development, the elevation of the crown level will likely cause
substantial increase in the cost of the works.
• Increasing maximum height from 462 m to 468 m would imply increasing the
height of the dam by 6 m, and consequently an increase of 26% in the maximum
height of the Amaila Dam and 30% in that of the Kuribrong Dam.
• Regardless of the economic incidence of this increase in dam height, there are a
number of aspects that should be considered in connection with the larger
flooded area and, in particular, associated environmental aspects.
10.2. ENHANCING THE DAM’S REGULATION CAPACITY
The use of a free spillway working without any control when the reservoir reaches
462.00m can be modified to increase its regulation capacity by installing gates to
control the levels and store surplus flows in wet months to be used in dry months.
The required modifications could be the following:
• Reduction in the level of the spillway lip to, for example, 457.00 m.
• Reduction in the width of the spillway to some 40 m in order to maintain its
regulation capacity.
• Implementation of circular sector gates allowing flows in wet months to be stored
and not spilled.
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• Adoption of reservoir operation rules allowing for adequate protection of the
necessary volumes to store flood flows.
The possibility of including these modifications will have two effects.
1. On the one hand, the resulting final cost could be smaller, mainly due to major
reduction in the volume of the RCC dam when the length and height are reduced.
An additional cost will be the installation of gates, the intermediate piles, and the
solution of associated structural problems.
Pursuant to the current Project, flood flows are automatically regulated without the
operator’s intervention, as the spilling begins by mere overflowing without human
action when the reservoir level is reached.
2. On the other hand, with reference to reservoir regulation and considering that
annual spilling in an average year is around 2.000 hm3, the regulation volumes that
can be obtained (no more than 200 hm3, in any case) indicate that it is not feasible
to enhance reservoir regulation in a substantial manner, considering that the
available volume would only be 10% of the average annual spilling.
The evaluation of this solution must contemplate the need to operate the reservoir
gates to control floods, as failure to do so may cause dam overtopping and associated
damage.
The following aspects should be considered:
• The need to have permanent control over the position of the spillway gates and
the reservoir levels.
• Alternative power supply to operate the gates, both externally and locally, by
means of on-site ancillary generation.
• Gate maintenance tasks.
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