II. Moderator's Report

The 14th Aspen PacRim Energy Workshop directed attention to continued strong prospects for growth in electric demand, and thus increased need for major additions to generation capacity. In particular, the meeting focused on the potential role of natural gas/LNG in the fuel mix for new generation capacity in the region. This Moderator's summary represents my views only in attempting to capture key points of the discussion; any errors or distortions are mine alone.

The presentations and discussions affirmed that there would be continued strong growth in electric demand in all counties of the region, and that this growth rate would be higher than other regions of the world. However, it was noted that the recent turmoil in financial markets likely will have an impact on the rate of economic growth in the Asia region, and this impact would lower (at least temporarily) the rate of increase in electricity demand in most countries in the region. It was also noted that electric demand elasticities are higher than energy/GDP relationships, so that electric demand may be less affected by the financial disruptions. In addition, new electric hook-ups bring a higher rate of demand than any other factor, and several Asian countries have large populations currently without electricity supply. As these populations are brought into service, consumption could increase rather sharply, depending, of course, on supply availability.

Further, financial uncertainties resulting from fluctuating exchange rates, weakness in banking sectors, policy changes, and other factors will likely slow the rate of external investment flows into power generation projects. Several externally financed IPP project delays, deferrals and even cancellations have been reported, and it is expected that more will likely follow. These project cancellations and deferrals, as well as slowed economic growth, will affect fuel supply arrangements for new electric generation capacity, perhaps even including some LNG export arrangements.

Competition among fuels for new electric generation remains robust, with coal, natural gas, fuel oil, crude oil, LPGs, Orimulsion and nuclear (in at least some counties) all remaining potentially viable choices. It was also noted that existing generation plants will probably continue to utilize the fuels for which they were originally designed and built. Thus, existing installed capacity for electric generation will remain in place for another 20 or more years, so new fuel choices largely will be limited to facilities constructed from this point forward.

There also was a general agreement that domestic energy sources tend to be favored in fuel selection for both price and supply security reasons, and that this is a tendency that will remain for the foreseeable future. In the absence of domestic energy resources, imports generally will be utilized on the basis of lowest cost, price stability and supply security considerations. In some cases, environmental considerations will bias imported fuel choice, but not at any cost.

Because energy resource endowments vary widely by country, imports of energy will remain a prominent feature of this region. In assessing the competitive differences among imported fuels, it appeared that gas was ranked high in preference for all countries--if the price were competitive with other fuel and technology alternatives. Continued technical progress and falling prices appear to have made natural gas/combined cycle plants increasingly competitive for electric generation--and for IPP projects in particular. Natural gas also has benefits in promoting better air quality, reinforcing the preference for this fuel when natural gas is available at a competitive price.

Because natural gas resources are less available in a number of countries with rapidly growing electric demand (China and Thailand particularly--and India, a potential competitor for exported gas), imports are a requirement. Due to distance from natural gas resources, gas must be sent either by LNG or very long pipelines. The cost of import facilities for LNG and for long distance pipelines must be added to the cost of the gas itself, and the resulting price of delivered gas has slowed penetration beyond wealthy east Asian economies despite a preference for this fuel. Again, the economic slowdown due to currency crises will raise barriers to LNG imports at current price levels. Because LNG export prices have been denominated in U.S. dollars, they have become more expensive to potential importers in the region. Such exchange rate movements likely will have to be absorbed by exporters if there is to be substantial expansion of LNG trade--either to existing importers, and certainly to new import markets.

Coal has remained a vigorous competitor in new electric generation, to the surprise of many. Domestic coal resources receive particular attention in those cases where ample reserves are available, and lost fuel costs are a powerful incentive for use in new electric capacity. The low fuel cost of coal is partially offset by higher capital costs and longer lead times in building new generators, and environmental controls add further costs to such facilities. However, stable costs and security of supply concerns help to keep coal-fired generation in active consideration. Even imported coal remains a strong competitor, since world coal prices have been in a stable-to-declining path. International coal markets are based on large reserves in several countries, so coal imports receive high marks for supply security.

One of the reasons that coal remains competitive with natural gas is the high cost of facilities to move gas to potential consuming countries. Over the past 20 years, LNG export projects have been built in several countries (Abu Dhabi, Alaska/U.S., Australia, Brunei, Indonesia and Malaysia) for sales in Japan, Republic of Korea and Taiwan. The majority of output from these projects have gone to Japan (80+%), with Korea and Taiwan taking up the remainder. LNG import growth has greatly decreased in Japan, but is stronger in Korea and Taiwan (though from much lower bases). All three of these countries have long-established LNG receiving terminals, storage and regasification facilities, so that incremental imports within existing facility capacity limits make such imports competitive to other imported fuels. LNG import prices for these countries are linked to a crude oil price formula, which has brought considerable price volatility over the past 20 years--with the price going well above imported coal during the period.

The discussion included a review of technology advancements that seem to hold promise for lowering the cost of long distance gas pipelines. Though shallow subsea pipes lead the cost reductions, similar advances may help the economics of land-based systems. Because pipeline gas imports do not entail the cost of LNG liquefaction, transport and receiving facilities, gas supplies within 3,000 kilometers, or even more, appear to offer some competition to LNG imports. Pipeline distances of these magnitudes may make available major reserves from within the region as well as from the FSU and Russia.

While the current three LNG importers have built extensive transmission and distribution systems, other potential importers must also build these facilities in order to receive either LNG or pipeline deliveries. The need for capital for both import facilities as well as internal distribution have some negative impact on future expansion of natural gas use in the region.

In addition, facilities to use natural gas for electric generation also must confront electricity markets which have been heavily regulated, and which have often been subjected to direct and cross subsidies to various classes of customers. To get a return on the capital invested in an electric plant, it is crucial that retail electric markets reflect open market realities. Some countries in the region have freed electricity prices from price controls, and this has enhanced prospects for IPP activities. Other countries have retained general price controls, but have permitted power purchase contracts from new IPPS which reflect open market conditions. Though some concern was expressed about the risk of contract abrogation in the latter case, IPP investors care mainly about the price they receive for electricity generated and sold by the IPP, so are relatively indifferent to full market deregulation. Of course, these same barriers are present for generation by any fuel, but the availability of financing does put a premium on a firm and competitive fuel supply source in order to secure sufficient funds for the power generation facility itself.

Note was taken of recent IPP activities where a firm, long-term fuel contract was crucial to total project financing, and failure to have such in hand was a major barrier to obtaining such financing. The discussion also indicated that for IPP projects, first cost is a crucial issue in obtaining both project approval and financing. While coal-fired generation has higher capital costs, most countries in the region have infrastructure for coal delivery/distribution. In those cases where natural gas infrastructure is not yet developed, ipp projects slated to use natural gas must either bear part of these costs up front or be able to demonstrate that delivery facilities will be available. Where natural gas is not currently available, the need for such a requirement can be a barrier to gas use. This is a classic chicken-and-egg problem, and one which potential exporters must be prepared to help solve if new natural gas/LNG markets are to be expanded. Other innovations in natural gas disposition were also discussed, notably several gas-to-middle distillates, gas-to-methanol and even gas-by-wire (gas-fired generation at the gas field, with electricity exported by high voltage--DC--transmission). It did appear, however, that the latter idea was of limited application, and would be in competition with pipeline gas exports. In all three cases, the appeal of such technologies would be for countries with large and remote gas reserves, and offered a way for them to realize economic value. It is less clear that countries interested in gas imports would find such technologies of great interest--except where the gas application in these countries could be substituted less expensively by the technology output.

The issue of government regulation of energy markets remains a key point in how quickly external capital may be made available for projects. While it is clear that all countries in the region are moving at some pace toward markets that are open to world prices, it is apparent that restrictions on open markets which still exist are limiting the rate of external funds for investment in the power and gas distribution sectors. In addition, recent turmoil in exchange rates and financial institutions in the region will be a further disincentive to many potential investors. Clear and consistent rules on such matters as currency repatriation, tax regimes, contract compliance, and exchange rate protection are required to limit the risk perceived by external investors; these are key items irrespective of the fuel choice issue. Clear steps to address such market imperfections will be important in encouraging external investment in key infrastructure projects in the region.

In addition to power generation, the PacRim region also faces significant challenges with respect to the oil market. Rapid growth in transport fuels has strained current regional refining capacity, and increasing imports of such products appear likely unless major refinery upgrading and capacity additions are undertaken. The region also is growing increasingly short of local production, and rapidly increasing reliance on Middle Eastern oil supplies will raise import costs for both products and crude oil. These costs, taken together with capital needed for refinery expansion and upgrading, will certainly increase financing competition for the electric generation sector. While external capital sources are readily available, the economic turmoil mentioned earlier will give pause to such investors. As a result, there will be growing competition for domestic funds for all required investments, with inflationary pressure on the economies.

The discussions found general agreement that opening energy markets will have beneficial results on economies in the region, especially in view of the high capital requirements to expand energy infrastructure--especially in the electric utility and natural gas sectors. Though the transition from strong government control, subsidies, and restrictions on investments and ownership from abroad may be complicated, the resulting efficiencies and increased economic growth are well worth the effort.

Though not identified as a separate item on the program, environmental matters recurred throughout the discussions. Such matters as air quality are increasingly important in urban areas, and are affecting fuel choice (or coal clean-up) for electric generation. Similarly, vehicle fuel standards are changing rapidly to minimize emissions from mobile sources. New and renewable energies remain of interest, though applications of such technologies as photovoltaics at the present seem limited to remote locations where the higher cost is competitive with extending electricity transmission lines. Wind power economics are increasingly competitive, but also limited to sites of favorable wind, transmission and distribution considerations. In general, it was agreed that while several renewable technologies may be of importance in the future, a substantial contribution was possibly several decades away.

Discussion of possible greenhouse gas emission restrictions emerging from the Kyoto meetings was limited, but most agreed that if restrictions were agreed to, it would have an impact on interfuel competition--certainly for new facilities, but less likely for existing ones. Which countries agreed to such restrictions also would make a difference. It was pointed out that newly industrializing countries considered threats from such a potential problem to be of little importance to them, and that there would be little likelihood of voluntary compliance with any policies arising from Kyoto. Thus, unless these countries agreed to any proposals in Kyoto, it was less likely that interfuel competition would be altered in a significant way for them. While several participants felt strongly that there was inadequate scientific data to support the assertion of a human impact on global temperatures, others felt there was a basis for concern, and still others thought carbon-limiting policies were possible in any event--at least by the industrial countries.

In summary, the PacRim discussions suggested that gas does have a major role to play in the electric generation sector (and in other sectors in some counties as well). However, the competition will remain vigorous from other fuels, especially coal in new, large generation facilities. Due to design factors, it is unlikely that further fuel switching will occur in existing power plants, so new locations will be the battleground in fuel selection. It is likely that LNG exports will remain attractive in existing markets which have a fully developed infrastructure, but price swings as a result of price linkages to oil imports remains a problem. Infrastructure costs in new markets will require very competitive pricing for LNG to succeed in opening such opportunities. Not only is coal (especially domestic, but also imports) a contender in such markets, but the economics of long distance pipelines is making such transportation increasingly attractive. There are no obvious winners among fuels in such competitive interfuel markets, and each new facility will be strongly contested.