1500KStreet
NW #330 Washington, D.C. 20005
1500KStreet
NW #330 Washington, D.C. 20005
| A |
s governments worldwide continue restructuring their energy
sectors to encourage private investment, there are struggles to create market
systems that foster bona fide competition among different generation resources.
The U.S. hydropower industry believes that the Clean Energy Initiative organized
by the White House Climate Change Task Force should play a major role in this
issue. Up to this point hydropower and other capital intensive resources have
been handicapped and kept from contributing their reasonable share of long-lasting,
emissions-free power to the benefit of national economies. Far less hydropower
has been developed in recent years than reason would dictate, with the greatest
share of new electric generating capacity being provided by thermal plants.
Despite U.S. cutting edge technology, repowering of existing plants,
and innovative plant efficiency practiced by U.S. private developers the rapidly
developing independent power producer sector is dominated by thermal generation.
The U.S. hydropower industry believes that the multilateral community and
the U.S. Government on behalf of U.S. companies will need to facilitate an
industry partnership to promote U.S. exports and ensure hydropower and other
non emitting technologies a level playing field in global energy markets.
Latin American and Asian markets have planned over 300,000 MW of
hydropower investment which is expected to come from the private sector by
2010, yet to date only 15 hydropower projects have been financed globally
on an international private sector basis. This outcome is not a consequence
of any inherent deficiency of hydropower in comparison to thermal but, rather,
results from structural problems in new and emerging energy markets that discount
the advantages of hydropower and highlight the disadvantages. Greater rationality
in financing would result in hydropower competing more effectively with thermal
alternatives.
The US Hydropower Council for International Development has identified
the following issues as being the areas where constructive changes could be
most beneficial toward facilitating new hydropower project development.
1. Disparity in Debt Repayment Terms
With movement toward more price-competitive electricity markets in the world,
hydropower projects are forced to compete on a short-term price basis with
other technologies. While hydropower has the advantage of having most costs
fixed over a project's operating life, it has the disadvantage of having higher
initial development costs than thermal alternatives. Hydropower has both higher
construction costs per unit of capacity and higher interest during construction
due to longer construction periods. However, hydropower projects have far
less operating risk, and will almost always have very low operating costs
which are little affected by inflation, volatile and uncertain future fuel
prices, or other external changes. Hydropower's advantages are not fully recognized
by the market. Nuclear projects already enjoy 15 year debt financing, yet
hydropower does not attract longer-term financing and is forced to compete
on 7-10 year financing.
Longer repayment terms are justified given the long useful lives
of hydropower projects and their minimal operation and maintenance expenses.
Debt repayment terms of 15 to 20 years beyond the date of commercial operation
are needed to make most hydropower plants competitive in the early years of
operation (during debt repayment). Longer debt terms reduce the political
and financial problems that result when power sales tariffs must be front-loaded
with high rates during the debt repayment period and much lower rates after
the debt is retired. With longer term financing, many sound hydro projects
can compete, over a useful life of 50 years or more, against any alternative
technology.
The finance term problem has been addressed in some cases by using
very complicated debt structures that includes World Bank guarantees for foreign
currency debt during the last few years of an extended loan repayment period.
Simpler structures (with lower transaction costs) are needed.
One option would be to modify the current Organization for Economic
Coordination and Development (OECD) consensus agreement relating to Export
Credit Agency (ECA)-supported debt and add hydroelectric power projects to
the special consensus on nuclear power projects. This already allows 15-year
repayment terms, subject to a slightly higher (appropriately so) loan costs.
This could readily be achieved with the support of the US Export Import Bank
representative at OECD ECA negotiations and/or through the US's permanent
representative at the OECD in Paris.
Another option is to establish dedicated long-term debt funds, with
the backing of multilateral lending institutions, to lend for hydropower projects.
Local currency debt could be managed by local development banks (e.g., the
Development Bank of the Philippines, and the Development Bank of Brazil (BNDES))
and the foreign currency managed by International Finance Corporation or other
lenders. Risk would be spread over a number of projects and countries, to
reduce the premiums. Strict technical and financial reviews of projects would
be needed to avoid abuse. In general, we believe that multilateral support
is clearly justified and necessary in order to offset the bias that favors
thermal generation over renewable hydroelectric generation.
2. Additional Financing Support
Hydropower plants face the burden of securing financing for local costs, which
can be from 40 to 70% of the total project cost. These costs are not generally
eligible for ECA-supported financing. Alternative mechanisms need to be identified.
To the extent that ECAs remain a primary supporter of national exports,
and the OECD consensus agreement limits local cost support to 15 percent of
total export costs, additional support should be sought from other entities
such as bilateral and multilateral development agencies. (It should be noted
that local development banks and local capital markets-with a few exceptions
such as in China and Malaysia-are not able to supply long-term local currency
financing for hydropower projects.)
Much needs to be done to focus and educate bilateral and multilateral
development agencies on the special needs and benefits of hydropower projects.
A significant concern is that the Overseas Private Investment Corporation
(OPIC) and the International Finance Corporation (IFC) will not consider greenfield
hydropower projects … and this refusal is simply because they lack understanding
of hydropower and its advantages.
For example, Hydropower will play a critical development role in
meeting carbon reduction commitments to address climate change goals. Hydropower
will also be a key resource in fostering sustainable development in developing
countries. To facilitate this potential, the World Bank's support for hydropower
needs to be more proactive and serve as a catalyst for other development lenders
to the sector.
It could be quite helpful if prospective lenders in this sector reviewed
and understood the World Bank's environmental guidelines. It is conceivable
that this could be accomplished at the instigation of the US Agency for International
Development (USAID) by their setting up a working committee from the World
Bank, IFC, US Export-Import Bank, OPIC, and USAID to review and refine these
environmental guidelines to develop institution-specific criteria and approaches
for lending in the hydropower sector.
On a specific note, the USAID experimental loan guarantee program
could be broadened to support hydropower projects within a pre-approved envelope.
Similarly, the World Bank could allocate a certain amount of its guarantees
(both partial credit and partial risk) for lending to this sector.
3. Ability and Willingness to Pay
In many countries, power purchasers do not have the ability (or sometimes,
the inclination) to pay for generated power. India is a prime example, and
Indonesia is now problematic. Additional in-country sector reform-already
encouraged by the World Bank, USAID, and others-is needed. Government guarantees
for power purchase agreements in financially unsustainable situations (in
many states in India, for example) should be discouraged. Developers should
be encouraged to avoid countries where the economic fundamentals and business
ethics do not support the prospect of payment.
4. Bidding Costs and Abuses
Firm
power cost bidding as a system for allocating project development rights is
a significant obstacle to private sector development of hydropower. There
are several problems with such a bidding system.
First, preparing bids for developing hydropower projects is extremely
expensive. Typically, a government-owned utility has identified a project
that it feels will be a good addition to the electrical generation supplies
in its service area. Enough studies have been completed to let the utility
believe that it has identified the optimum development. The utility then solicits
bids for BOT (build-operate-transfer) development, with developer selection
based on the minimum bid price for energy and power supply during a concession
period. The project becomes the utility's property at the end of the concession.
To prepare the bid, a developer must estimate output by evaluating
hydrology (water availability) and efficiencies; determine project costs (land
acquisition; construction costs including access roads, transmission lines,
project civil works, and mechanical and electrical equipment; operation and
maintenance cost; and financing costs); determine a permitting and approval
plan; prepare a detailed project implementation schedule; and arrange preliminary
financing. Preparation of such bids can easily cost more than a million dollars
for each developer. There is never enough detail, or assurances of correctness
of project fundamentals, provided in the bidding package to allow inexpensive
bid preparation.
Further, the developer and his team are given little flexibility
to improve an identified project. The utility often cites the need to make
competing proposals easier to compare, or to use its standards since it will
own the project after the concession expires. However, these attitudes are
seriously counterproductive-and squarely at odds with the goal of producing
competitively priced power.
In addition, the bids submitted are usually not considered final
bids by the utility, but simply starting points for further negotiations.
Subsequent negotiations invariably damage the developer's position. In the
Philippines, for example, very large performance bonds posted with bids are
held hostage during these negotiations, and a developer who walks away risks
forfeiting a very large amount of money.
Two options seem to be preferable, where projects are already identified:
--First, the potential power purchaser could select a developer for
a project by competitive review of qualifications, with a target tariff already
established. The selected developer would be given a project concession valid
for no more than two or three years. During that time, the developer should
have considerable flexibility to develop a firm price power purchase contract
and present it to the purchaser. The purchaser would compare the proposed
terms to its alternatives and accept or reject the contract. Negotiations
could proceed if warranted. If the contract were rejected, the project could
be dropped or offered to others depending on the purchaser's needs. The first
developer (and his team members) would not be eligible for a second chance.
--Second, the utility/purchaser could prepare more detailed project
documentation and accept all hydrologic risk and share a significant portion
of construction cost (and geologic) risk.
5. Allocation of Project Risks
Where a Power Purchase Agreement (PPA) and non-recourse financing is used,
hydrologic risks should be partly accepted by the power purchaser. A significant
power (capacity) tariff component should be included in the contract for power
and energy sales (assuming the system is not dominated by hydropower). As
long as a plant is physically available for generation, the power component
should be paid even when water may not be available. Ideally, the power component
should cover debt service completely. Hydrologic risk associated with run-of-river
projects-and per kilowatt-hour energy costs--would be reduced if higher plant
factors than are often sought were used in sizing developments. Especially
in areas with sparse hydrologic data, run-of-river plant factors of 30 or
40 percent make little sense. A corollary is that use of traditional government
resource development agency economic assessments will result in non-price
competitive sizing of site developments. As discussed earlier in connection
with bidding systems, the power purchaser should share construction cost and
schedule risk if competitive bids are prepared based on information from studies
provided by the purchaser.
* If you have comments or questions regarding the issues discussed
in this paper, please contact Debby Stone, US Hydropower Council for International
Development at:
1500KStreet NW #330 Washington, D.C. 20005
(202) 383-2536 fax: (202) 383-2555, e-mail debbys@ us-hydropower.org