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Moving a Geothermal Project from Concept to Commercial
Reality
Peter BarnettSinclair Knight Merz (SKM)
Introduction
• In moving a geothermal project from concept to commercial operation, we follow a program of sequential stages from initial exploration through to commissioning
• Objective is the discovery and proving of the required: – quantity, and – quality of geothermal energy
• Is now a more or less standardized industry process
Key stages in geothermal development
• Pre drilling exploration model– To determine whether a project is worth drilling
• End of exploration drilling evaluation– Feasibility Study
• Commitment to proceed with development• Establish a nominal size and cost of development
• Development– Combination of delineation and development drilling
• Continued resource evaluation– Detailed engineering
• Steam field• Power plant
– Construction• Ongoing production drilling
– Commissioning
Key issues in the development process
• At all steps in this process we need to deal in detail with issues of:– Timing – Costs (capital)– Risks– Returns
Staged Geothermal Exploration & Development
1
10
100
1000Activity 1 2 3 4 5Project identification / reconnaissance
Geology and geochemistry
Geophysics
Prefeasibility study
Exploration drilling, well testing
Resource assessment, feasibility study
GO/NO GO
GO/NO GO
Permitting / EIS
Infrastructure (pads, roads)
Commercial negotiations to PPA
EPC Manufacture
Preliminary design
EIS, permitting
Development / production drilling
GO/NO GO
Establish EPC contract
FINANCIAL CLOSURE
EPC Construction
COMMISSION
CumulativeCost, US$ M
Time, years
Nominal timing and capital cost requirements for a 100 MWe “Greenfield” geothermal project
Project timing
• Timing– Greenfield developments
• Typically 60 months required from first surface exploration– 24 months for surface exploration and exploration drilling– 30 to 36 months to develop project from time of commitment
» (feasibility study)
– Brownfield developments • less time required as fuel supply is not such an issue
– Field expansions– Infield optimisation plant
• project timing largely dictated by time for equipment supply and installation
– Can be only a few months» eg topping turbines
Project costs …1
• Capital Costs dependant on:– Well costs
• reservoir depth• well productivities• field enthalpy• steam field collection system
– Type– Pressure control system
• number of injection wells – Power Plant
• cycle type • plant size• inlet pressure
Project costs …2
• Initial estimation of project capital costs – Well costs
• assume USD 1,200 to 1,500 per m– Steam field collection system
• wet steam field– assume USD .35 to .40M per MWe
• dry steam fields– assume USD 0.20 to 0.25 MWe
– Power plant• dependant on cycle type• significant economies can be achieved with:
– increased unit size– increased inlet pressure
• overall unit capital cost estimated to vary from US$1,600/kW to US$2,500/kW (McVeigh, 2003)
– depending on project size and other project-specific criteria
Sanyal (2005) eqn fitted to McVeigh (2003) data
$1,500
$1,700
$1,900
$2,100
$2,300
$2,500
$2,700
0 20 40 60 80 100 120 140 160
Power Plant Size (MW Capacity)
Tota
l Pro
ject
Dev
elop
men
t Cos
t (U
SD/ k
W)
Cd = 2500 e -0.003*(P-5)
• Cd = capital cost in US$ / kW• P = plant capacity in MW
Key issues for commercialization
• Although the activities undertaken in the “Key Stages in geothermal development” are important, there are two essential requirements for project commercialization:1. Securing project funding
Need funds in two amounts:• exploration drilling (e.g. USD 10 to 15 M)• for the power development (e.g. USD 100 to 150M)
– requires packaging of the project in such a way to make it financeable
2. Commissioning:– i.e. the commencement of commercial generation
and thus revenue with which to repay loan funds
Sources of Funding …. 1
• Exploration drilling– Government agencies
• government funds• grant funds
– (e.g. international assistance, foreign aid agencies)• concessionary loan funds
– WB, IFC, JBIC, ADB – Developers
• internal reserves• commercial loans
– Exploration drilling seen to have a high risk profile• presents a barrier to exploration drilling and thus the creation
of new projects for development
Sources of Funding ….2
• Development funding– Government
• Concessionary loans– Private Sector
• Internal reserves• Commercial loans
• Development projects have a lower risk profile and funding is thus more readily obtainable
• Funders are seeking projects with greatest potential for:– technical and economic success– coming on-line within a reasonable time frame
i.e. having minimal legal, institutional and environmental risks
Role of government vs. private sector
• Once exploration projects are proven viable and development risks reduced, then private sector is much more likely to participate
• Its all a question of risk and return on capital– Governments take a utility viewpoint with relatively
low IRR expectations – IPP’s view risk as requiring a greater return on capital
with IRR’s of 15%, or probably higher
Role of government vs. private sector
• SKM view is that:– Government agencies remain best placed to handle
exploration drilling and resource proving• as government is in the best position to accept the risk
– Subsequent field development can then be undertaken by the private sector and/or government
• To ensure active involvement of the private sector in geothermal developments, government needd to set the appropriate incentives:– a power price which adequately compensates the
private sector for: • cost of money in the commercial sector• development risk
– and provides contractual and regulatory certainty
Geothermal Risk Issues
• As project commercialization progresses, the term “RISK” arises ever frequently
Geothermal Risk Issues
• Key geothermal risk issues include:– Pre development
• exploration risk (of failure) • environmental risks • regulatory
– new geothermal law (#27 / 2003)– regional autonomy law (# 25/ 1999)
– Development • fuel risk (for start up)• construction risk• plant performance
– Commercial operation• long term fuel risk• commercial risk• currency risk
Probability of Success vs Exploration Stage
0%
20%
40%
60%
80%
100%
120%
Desk T
op
Recon
n.
Geoph
ysics
Explo
Drlg
Deln D
rlg
Feasib
ility
Intial
Prod
n Drlg
Financ
ial C
losure
Prodn D
rlg
Injec
n Drlg
Constr
uctio
n
Phase
% P
roba
bilit
y
MEAN
MAX
MIN
Probability of Proving a Viable Project
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
Desk T
op
Recon
n.
Geoph
ysics
Explo
Drlg
Deln D
rlg
% P
roba
bilty
MEAN
MAX
MIN
Exploration risk• Once exploration drilling has been completed and a
resource proven, subsequent development risk is much reduced
• This is support for the view that Government should remain in the business of exploration drilling and resource proving, to reduce project risk
• Risk reduction supports are becoming increasingly available to Governments:– CDM and carbon trading– ARGEO type mechanisms
• regional revolving funds for exploration drilling • drilling failure insurance mechanisms
• an overall continuing maturity of the geothermal industry with improved understanding of geothermal systems and models etc
Rationale of Risk Guarantee Fund
Role of the RGF
African Rift Geothermal Development Facility Sequencing
Resource assessment Drilling
FeasibilityStudy/
Tender
Geothermal Power Plant Development
Resource assessment Drilling
FeasibilityStudy/
Tender
Geothermal Power Plant Development
Resource owner’s responsibility Investor’s responsibility
Resource assessment Drilling
FeasibilityStudy/Tender
Geothermal Power Plant Development
Resource assessment Drilling
FeasibilityStudy/Tender
Geothermal Power Plant Development
Resource assessment Drilling
FeasibilityStudy/Tender
Geothermal Power Plant Development
Geotherm
al R
esourceA
ssessment
Netw
ork
Risk
Guarantee
Fund
TransactionA
dvisor
Geotherm
al Pow
er PlantD
evelopment
FundingSchem
e
Transition
T i m e A x i sT i m e A x i s
Fuel Risks
• Start Up Fuel Risk – Reserves assessment
• required in advance of development funding• historically has been based on volumetric stored heat
computations• now based on numerical modelling simulations based largely
on model matching to reservoir natural state
• Long Term Fuel supply Risks– Largely an O&M issue, managed through:
• staged plant expansions• detailed reservoir modelling based on:
– closely matching actual field performance with time– detailed geochemistry
• active reservoir monitoring and management programs
Commercial Risks
• Key issue is the ability of the project to generate sufficient income to:– repay project loans– meet O&M costs – meet companies profit requirements
• (for private sector companies and becoming an increasing requirement for corporatized or partially privatized government companies)
• Dependant on:– selling price of power
• as locked into PPA– loan interest rate and IRR– long term contractual certainty
Example project cash flows # 1
-50,000,000
-30,000,000
-10,000,000
10,000,000
30,000,000
50,000,000
70,000,000
90,000,000
110,000,000
130,000,000
150,000,000
0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30Project Year
Cas
h Fl
ows
USD
Interest Expenses (US$)
Loan Principal Repayment (US$)
Net Cash Flow
Interest Income (US$)
Cash Balance(US$)
LOAN INTEREST RATE = 3.5%
Example project cash flows # 2
-50,000,000
-30,000,000
-10,000,000
10,000,000
30,000,000
50,000,000
70,000,000
90,000,000
110,000,000
130,000,000
150,000,000
0 2 4 6 8 10 12 14 16 18 20 22 24 26 28 30Project Year
Cas
h Fl
ows
USD
Interest Expenses (US$)
Loan Principal Repayment (US$)
Net Cash Flow
Interest Income (US$)
Cash Balance(US$)
LOAN INTEREST RATE = 7.0%
Conclusions … 1
• A staged geothermal development process is essential during project commercialization - for risk reduction
• Securing project funding is the single most important step in the commercialization / development process– Exploration drilling – Development
• Government should remain in the exploration and resource proving phase– able to handle the higher front end project risk – can avail of risk reduction mechanisms not available to IPP’s
• IPP’s and / or Government undertake development– privatization model argues that IPP’s will be more efficient– but, still under vigorous debate (worldwide)
Conclusions … 2
The key risk issues are not technical but are:• Regulatory
– uncertainties remain in: • geothermal law• implementation of regional autonomy law
• Commercial– ability of project to generate sufficient income to meet
all obligations• selling price of power
– cost of money and attached risk premium• long term contractual certainty
• These issues merit continued strong interest and advocacy by the Indonesian geothermal industry