Too many new power plants were built in the United States in the 1990’s and that led, together with the slowdown in economic activity, to a slump in wholesale electricity prices from which the merchant power industry has yet to recover. By 2003, some regions of the United States, like the Entergy service territory, had more than a 60% reserve margin — or spare generating capacity above what was required to satisfy electricity demand during peak hours — and even the area with the least capacity — Florida — had almost a 20% reserve margin. Predictions varied about how long it would take to work off the excess to a point where additional power plants would be needed. 

Chadbourne hosted a roundtable discussion in late January about the outlook for domestic electricity prices with three prominent forecasters. The following are excerpts from the discussion. The speakers are Mark Griffith, a vice president with Global Energy Advisors, Art Holland, director of forecasting for Pace Global Energy Services, and Steve Dean, president of DAI Management Consultants. The moderator is Keith Martin.

Reserve Margins

MR. MARTIN: Where are reserve margins highest and where are they lowest today in the United States?

MR. GRIFFITH: The highest reserve margins today are in the ERCOT market in Texas and in the southeastern United States. Measuring reserve margins is always tricky, but I would say the lowest is in the Long Island area and New York City That seems to be the area with the most urgent need for
additional capacity.

MR. MARTIN: And what percentage reserve margins are we talking about in places like the Entergy service territory versus New York and Long Island?

MR. GRIFFITH: The last time I looked, the Entergy reserve  margin was still close to 60%. In the New York City and Long Island area, if you just look at indigenous resources, the reserve margins are negative. It is actually planned that way. 

The region expects to rely heavily on imports to meet peak loads, and the reserve margins are currently in the range of minus 10 to 15%. That is not necessarily a bad thing. Many cities rely on imports. However, there is pressure to reduce the shortfall, and you will see some projects in 2005 and 2006 like East River and Astoria coming on line to help.

MR. MARTIN: Does everyone agree with that ranking of reserve margins?

MR. HOLLAND: I agree in general. I do want to caution, though, that it is not a good idea to use the reserve margin as a sole indicator for the need for new capacity. You are looking at a measure of supply and demand imbalance that focuses on a single hour during the year. That said, in general, I think that the assessment was accurate. The reserve margins in ERCOT are high. Entergy remains very high. You have some parts of the Midwest that are still fairly high. Maine has a fairly high reserve margin still. You also have, by that measure, a fairly high reserve margin still in most of New England, or NEPOOL.

You also have to be careful with measuring capacity. For example, you don’t want to apply all of your hydroelectric capacity to your reserve margin. Hydroelectric power is not so much a capacity-limited resource as an energylimited resource. 

MR. MARTIN: What does that mean?

MR. HOLLAND: It means that you don’t necessarily want to rely on all of a hydroelectric facility that is rated at 500 megawatts to be available during the peak summer demand period. The water supply might not be adequate with the result that the plant might be unable to produce 500 megawatts when you need it.

MR. DEAN: I generally agree with the other commentators, but would like to point out a couple things. It is very difficult in most regions of the country to make unqualified statements about capacity factors. In the late 1990’s, many more gas-turbine combined-cycle power plants were built than were needed. Many of these plants were halted in mid-construction and have sat idle. The reported figures mask this underutilized capacity. For example, in the southeastern United States — the area called SERC — we estimate that there is probably 20 to 25% additional capacity than you see in the reserve margins people quote due to unfinished plants or plants that have been mothballed. This is due partly to spiraling natural gas prices. They have gone up faster than most people predicted 12 or 18 months ago. Electricity prices have also increased in most regions of the country, but not enough to draw gas turbines into operating longer hours. In other words, fuel prices are increasing faster than electricity prices. The capacity factor for gas turbine projects is actually going down. 

The one positive development is the growth in demand for electricity exceeded the additions to capacity in 2004 for the first time since 1999. 

MR. MARTIN: In which regions of the country is the demand growth outstripping supply growth?

MR. DEAN: I think that is a general statement that is true basically in all regions of the country. As the economy has picked up, so has demand for electricity. And we have not  seen a corresponding growth in supply.

MR. GRIFFITH: The one exception is the western United  States where we are seeing a construction boomlet. We expect to add something on the order of 4,000 to 5,000 megawatts a year for the next two years — 2005 and 2006 — in the WECC, which is the western part of the US. 

MR. HOLLAND: Mark, I suspect you are talking more about California and Utah than the entire WECC.

MR. GRIFFITH: Most of the activity is in California and some of the adjacent states, as opposed to the Rocky Mountain states. Arizona has also had a building boom and is trying now to figure out how to get the power to market. 

Areas of Need

MR. MARTIN: Art Holland, what are the important factors in assessing whether there will be a need for more power plants — reserve margins, spark spreads, electricity prices, fuel prices, what?

MR. HOLLAND: In general, it is some measure of reliability. Despite my earlier comments, reserve margins are used as shorthand for that. Other organizations that are still under a more regulated type of a structure might use a loss-of-loadprobability-reliability standard. 

In more competitive markets, it may be useful to look more closely at prices and the point at which prices will start to justify new construction. Current prices do not justify new construction in the southeastern United States and perhaps not quite yet in the Midwest, but they are more competitive in the Northeast and California.

MR. MARTIN: Those areas offer perhaps the greatest opportunity for new construction. What is next on the list — Florida?

MR. HOLLAND: Florida is a unique situation. In Florida, you cannot build a power plant with a steam turbine in it over a certain size unless you have a contract with one of the local utilities. That was the issue surrounding the New Smyrna Beach Duke project, where the Florida Supreme Court sided with the utilities by confirming that you have to have a state permit in order to build a power plant with over a certain size
steam turbine. Florida is in a fairly tight supply-demand situation, but there are legal impediments to new construction.

As far as working off the excess capacity most rapidly, you are already seeing pockets of need in New England. Boston and southern Connecticut are in need of capacity now and, as was already mentioned, New York City and Long Island have a continuous need for new capacity. The earliest other places where I would expect to see an early need for new capacity is Oregon and Washington. This might be less for energy requirements as for reliability requirements because of the high level of hydroelectric dominance there. The ECAR region — the “rust belt” states and, in particular, Michigan or what they call the MECS
subregion — may be affected by Ontario’s announcement that it will try to retire about 7,500 megawatts of coal capacity, some of which is old, but quite a bit of which is baseload capacity. That could create an imbalance between demand and supply in Michigan. You are seeing a similar situation in what used to be call MAPP, which is further west, and is now called MRO. This is the Dakotas, Minnesota, Wisconsin, and
Nebraska. Xcel has already said that it needs several thousand megawatts of capacity.

MR. MARTIN: So we are beginning to see need.

MR. HOLLAND: Yes. We have been saying at Pace Global for a couple years now that you will start to see a recovery from the wholesale suppliers’ perspective as early as next year. The market will not have recovered, but we will start to see signs of a recovery from the overbuild. 

MR. MARTIN: As recently as a year and a half ago, forecasts were that you would start to see a recovery in places like Florida first, but it would be as late as 2015, or even later, before the recovery would reach places like the Entergy system. Has that time period shortened? Are people more optimistic about a recovery than they were even a year and a half ago?

MR. HOLLAND: Entergy is an extreme situation for a number of reasons. One is it was very easy for suppliers, private investors and development companies to get into certain parts of the Entergy service territory. There were no regulatory impediments. They were welcome to come build plants. The result was the area was extremely overbuilt. There is also some question about how much transfer capability in terms of transmission exists between Entergy and the surrounding area, which may make it difficult for that power to find a market outside of the Entergy area. You have a regulatory situation that is not conducive to
competitive power, where you have very strong incumbent utilities, and the wholesale competitive market does not provide liquidity. It does not provide visibility in terms of price formation. There is not a lot of opportunity for nonutility suppliers to sell their power there. And they are in a highly overbuilt area.

MR. MARTIN: Steve Dean, do you want to comment on what we have been discussing? 

MR. DEAN: Yes. Let’s note that we are seeing some fairly substantial development activity taking place with respect to coal-fired generation. More than 100 new coal-fired plants are in various stages of  development currently in the United States. Several coal-fired power plants in such places as New Mexico and other western states have been financed recently and started construction. In my mind, the question
is not only where the areas are where reserve margins or capacity factors or even spark spreads support new capacity, but also what type of capacity should be built. I think we are seeing the answer to that question is that many of the new plants will burn coal. That is certainly true if you believe that natural gas prices will remain in the $5 or $6 an mmBtu range and you believe that electricity prices will not increase
significantly in the near term. 

MR. HOLLAND: I agree that is an extremely important point. The economics of coal-fired generating capacity are more attractive now than they have been in years. However, I would caution that coal is not a solution for every part of the country. It is difficult for me to imagine that we will see a lot of coal capacity built in very regions that we have said are likely to offer the earliest opportunities for new construction.
Boston, southern Connecticut, New York, Long Island — I have a hard time imagining that you will see a coal-fired power plant built there. However, having said that, one of the technologies that looks like it may be starting to catch fire is IGCC technology. I don’t want to suggest that we will see a large number of new integrated gasification combined-cycle power plants built soon, but the technology is starting to look more attractive.

MR. MARTIN: And the reason that it is more attractive is the capital cost per megawatt of capacity is far more expensive than for other types of power plants, but it is a cleaner way of using coal?

MR. HOLLAND: It is more expensive than a gas-fired combined-cycle power plant, but it may be comparable in cost to a conventional coal-fired steam-type power plant. 

MR. GRIFFITH: We planned originally on this call to talk about the electricity price outlook and the parts of the US where they might be price opportunities, but the discussion broadened quickly to cover a lot of other topics — local reliability, the resource mix, the need for energy versus peaking capacity — and this gives you a sense of the overall complexity of the problem.

One of the things we have seen is that, as various regions recover from the supply overbuild, the  transmission system is not allowing you to move the spare capacity around freely. 

There is a limit to how much electric transmission capacity exists in places like the upper Midwest, and this creates a need for new construction even in the face of a continuing oversupply in the southeastern United States. 

If you look at a map to see whether you can move electricity between regions, the answer is you can 80% or 90% of the time, and this is one the factors contributing to depressed wholesale electricity prices in the Midwest, but you cannot move it during peak hours. That means you still have to build to maintain local reliability. It is the need for reliability that is behind the pockets of opportunity in places like Florida and the upper Midwest. There is a real need in these places, but it is due to the fact that they cannot get the
capacity from other regions where there is still an overbuild.

It makes for an interesting dynamic. It also shows that price alone is not what is spurring new construction, at least not at current energy prices.

We are struggling as a nation with how to fund construction of this new capacity when there are still adjacent overbuild markets in this country. What is happening is utilities with a need for additional capacity to satisfy reliability needs are entering into bilateral contracts with independent power producers to provide specific identified resources that are used to satisfy the need. This is not the competitive model that people were envisioning 10 years ago, but it is a response to the reality on the ground. 

Locking in Supply

MR. MARTIN: Electricity prices are still low but are expected to increase. Are you seeing a greater willingness on the part of utilities nationwide, or just in particular regions, to sign contracts to lock in supply at current prices?

MR. GRIFFITH: Somewhat. The utilities with whom I have been working on integrated resource planning projects realize they need to sign some contracts to demonstrate that are not just interested in building power plants themselves. However, they have a concern about how long-term power purchase agreements affect their capital structures. When they build on their own, some of the capital comes from debt and some of it comes from equity. But when they sign a contract to purchase power, there is no chance to invest any equity. The demand charges under the purchase power agreements are treated like debt. This makes their debtequity ratios look worse and is a concern when they come up for review by the rating agencies. Any utility that sign a lot of power purchase agreement might be asking for a downgrade in its credit rating, which would increase the cost of its debt. Utilities are struggling with this.

MR. MARTIN: Art Holland, are you seeing utilities under pressure in any parts of the county from their regulators to lock in long-term supplies of electricity while the prices are still relatively low?

MR. HOLLAND: Not directly. What I am seeing is utilities must show a level of prudence in their resource planning. Regulators are not saying prices are low so go out and buy, but they are insisting that utilities demonstrate prudence in their decisions whether to buy power from wholesale suppliers or to build their own power plants.

MR. MARTIN: Steve Dean, do you think it would be sensible for utilities to lock in supply at current prices? Are prices basically going to go up here?

MR. DEAN: Duquesne Light, which divested itself of all its generating assets, went to the Pennsylvania Public Utility Commission with a plan to purchase electricity, I believe, on a six-year contract. The
commission rejected the plan. It wanted to shorten the contract period.

I think it makes sense to try to lock in long-term supplies because electric prices over the past year or so have been at historic lows, but as the experience in Pennsylvania shows, utilities in some cases are being prevented from doing so.

MR. MARTIN: Art Holland, would utilities be prudent to lock in supplies at today’s prices?

MR. HOLLAND: The expectation in general is that prices will increase. I want to be careful that I don’t say prices, but spark spreads. Prices tend to follow the general direction of fuels. As natural gas prices go up or down, you will see a corresponding change in the price for electricity. What is important is the spark spread, or the difference between the cost of inputs and what a generator can get for his electricity. The question isn’t whether it would be wise to lock in prices when they are expected to increase. Utilities have to answer to their public utility commissions. They have to put together integrated resource plans that are consistent with the goals and objectives of the utility commission. The commission is interested in more than just the cost of electricity. The plan must also be consistent with the type of market that the
commission is trying to encourage in the state.

That said, I think that it would be very prudent for large industrials with access to wholesale power to take a serious look at the prices in their area, and coupled with prudent risk management practices, look at entering into some longerterm contracts.

Trends

MR. MARTIN: Let me circle back to a question I asked Art Holland, but ask it this time of Mark Griffith. Are things looking rosier today for merchant generators than they were just a year and a half to two years ago?

MR. GRIFFITH: Rosy is a relative term. Things are actually playing out pretty much as expected. Go back two years. There was an expectation that prices would begin to recover as early as 2003 to 2004. What we saw was that most of the power plants that were under construction were actually completed, with the result that the overbuild got extended for another year or so. Now it is 2005, and we are seeing a recovery in the spark spread and it is not far off from what we were expecting.

The capital for investing, for refinancing, and for picking up distressed assets and keeping them in the market is much greater than we were anticipating. We thought that there would be more of a pullback from investors, especially the banks in New York who would not want to play in this game. What we see instead is a lot of money available for investment. It is not coming from traditional bank sources, but from private equity firms.

MR. MARTIN: Steve Dean, is the market recovering, in your view, faster than people were anticipating even a year or two ago?

MR. DEAN: I would argue that it is not, and the reason is clear if you look at the economics of gas-turbine combinedcycle plants. With gas at $6 an mmBtu and a 7,000 Btu-perkWh heat rate, the owners need $42 an mWh just to cover their fuel prices, and electricity prices are currently in the $40 an mWh range. For these plants to be profitable, prices will have to move above $50 an mWh. We are not projecting that
in the near term. The point is it remains a very tough environment for owners of gas-turbine combined-cycle plants, and it will remain tough for the next several years.  

MR. MARTIN: Calpine, which is heavily invested in gas, says it expects the next wave of power plant building around 2008 or 2009. Is that consistent with your projections?

MR. DEAN: It depends on the region of the country. The most likely places where there will be such opportunities are in Florida, the New York ISO, and maybe some parts of the Midwest — for example, west of Chicago — as well as California, but with California, the question is how much of the need will be met through imports from the surrounding states.

MR. MARTIN: Art Holland, each of you seems to agree that the best opportunity by fuel type in the short term is coal. Is that because coal prices have not risen as rapidly as gas prices?

MR. HOLLAND: I’m not sure that I agree completely with that statement. In the parts of the country where you will see the need for additional capacity the soonest, coal may not be the best answer. While over the longer term, you do see an increase in the opportunities for new coal-fired power plants, I think that you have to temper that with environmental concerns and the longer lead times associated with coal. It takes longer to develop a coal plant than it does a gas plant.

MR. MARTIN: Well, that leaves a fairly confused picture, because the greatest demand is in regions where coal doesn’t work. Why does coal get built then in parts of the country where the demand is not so great, and what gets built in the places where it is great? 

MR. HOLLAND: The proximity to coal resources is conducive to construction of coal-fired power plants, as is the lack of proximity to densely-populated areas, which generally gives rise to heightened concerns about the environment.

The environmental barriers to coal may eventually be overcome with IGCC plants, although I am not saying that we are throwing our hat into that ring just yet. We are looking at IGCC, and it is certainly looking more and more attractive.

MR. MARTIN: Mark Griffith, going back to you — Chadbourne had a conference in San Diego two years ago, and we talked about renewable portfolio standards, now in 18 states, that require utilities to generate or buy a certain percentage of their electricity from renewable sources. Is it possible that all the additional
capacity required in the country, at least in the nearterm, will be taken up by wind, geothermal and other renewable suppliers, and there won’t be much room for more traditional merchant power companies?

MR. GRIFFITH: That’s an interesting way of putting the question, Keith. Wind generation is a different type of capacity than a coal- or gas-fired power plant that is dispatchable. Early in this discussion, the point was made that you must be careful with counting capacity from hydroelectric generation due to its unique characteristics. The same thing is true for wind capacity, and even more so.

The renewable portfolio standards in 18 states plus the tax credit that the federal government offers wind generators is creating a building boom. You asked what the nearterm opportunities are. Wind generation is definitely a near-term opportunity. Some electric utilities are also putting wind generation into their resource plans, even without being required to do so under a state renewable portfolio standard, because they want to take the lead on environmental activism and bluntly offset some of flak they expect to receive in the regulatory arena as they build a traditional fossil fuel plant. We are tracking renewables at Global Energy. We are expecting at least 10,000 megawatts in additional renewable capacity to be added in the US in just
the next few years, and it could be a lot more than that. 

However, all that aside, the capacity is generally not counted toward the capacity needed in reserve margins. The wind generation is not coincident with the peak demand for power in most regions, with a few exceptions like in California where there is a closer correlation between when the wind blows and periods of peak demand. 

MR. MARTIN: So load growth will not be taken up by renewables for the reason that one cannot count on wind as baseload power?

MR. GRIFFITH: That’s right. It is generally not baseload, with the possible exception of California. In other parts of the US, you often find the best wind resource is in the spring and the fall and not during summer when the loads are the highest. It is also not dispatchable. You have to take it when it is there. You are glad to have it because it is incrementally at a very low cost, but it is not a reliable resource.

The bottom line is if you end up putting in 10,000 megawatts of wind resources across the US, you will probably put in at least another 9,500 megawatts of some other type of resource, typically something that burns fossil fuel, in order to back it up.

MR. DEAN: The electricity center at Carnegie Mellon University did a study of how deployment of a large number of wind turbines would affect weather patterns in the United States. It found there would be a potentially significant effect. A large deployment would change the air flow and velocity and, therefore, the weather patterns. The study has not received much attention. Wind has a lot of momentum and political support at the moment, but it could become more controversial as wind farms become more
widespread. 

MR. MARTIN: That’s very interesting. Is Washington, DC expected to be warmer or colder?

MR. GRIFFITH: I can’t answer that question off the top of my head.

The Next Peak

MR. MARTIN: New direction — the merchant power market in the United States is characterized by periods of boom and bust. It is a little like the farm sector before the 1930’s where every farmer had an incentive to maximize output, but if everyone pursued that strategy, the entire sector would be impoverished. We just went through a bust that started in 1999 and lasted at least through 2002 or 2003. Art Holland, if you were plotting a line, would it show the market now moving back in the direction of a boom and where would be put the next peak?

MR. HOLLAND: Yes. We are starting to breathe again. We are coming out of our coma. I would put the next peak somewhere around 2010.

MR. MARTIN: It will be upward from here until 2010, and then back down again?

MR. HOLLAND: Let me give a little broader range: 2010, 2011, 2012, I think will be a good range for when there will be a peaking out. Several parts of the country will need new capacity by then that have not been mentioned, including most of ECAR — the rust belt states. ECAR will start to need capacity by the 2012 to 2013 period. PJM may be looking for new capacity as early as 2012. We will see a general need for new generating capacity by about that period.

MR. MARTIN: Mark Griffith, if you were plotting the bust and boom, where would you put the peak of the next boom, and do you agree that this industry will continue to be characterized by boom-and-bust cycles?

MR. GRIFFITH: I agree that it is a boom-and-bust-cycle industry. It has that characteristic in common with many industries where a very large capital outlay is needed to bring new production capacity online. You see the same cycles across many industries. The period 2010 to 2012 is a pretty good time to be thinking about a peak in terms of when things will be from a supplier’s point of view. There should be a little more discipline on the financing side this time to help keep the boom under control. The risk is that everyone is anticipating this peak at about the same time. The resources are already lining up to meet the demand. There is certainly the risk for project developers to create another bust cycle pretty quickly. A lot of the new
generation under study is gas-fired combustion turbines and combined-cycle units that have relatively short lead times to build. You can build such a plant in a two- or three-year period, depending upon how far along you are in your permitting. Developers are in a position to respond quickly to improving market conditions. If they start building such plants on balance sheets with the hope of lining up a power
contract near the end of construction, we could see another bust cycle take hold quickly.

MR. MARTIN: Steve Dean, do you agree with that time horizon? And do you agree with the last statement about the potential for a fairly rapid bust after the next peak?

MR. DEAN: I think the next development cycle will be very different from what we saw in the 1990s. There has been a lot of discussion about nuclear power. The economics for nuclear power plants are  advantageous today in relation to gas-turbine combined-cycle plants. If gas prices remain high and if the regulators allow new nuclear plants to be permitted fairly quickly, I think you will see the large utilities start to build nuclear plants here in the United States. And if that happens, it will create a bust for the  independent power producers because nuclear plants are now the low-cost producers in the United  States.

MR. MARTIN: But surely that cannot happen within the time horizons we have been discussing? Nuclear takes so long to permit and build. 

 MR. DEAN: That was true during the 1980’s and it is the key question today: can the time horizon be shortened to the point where nuclear plants could be put into service and meet some of this projected demand by 2008 to 2010? A lot of people are starting to look at that question. If they succeed at shortening the timelines, it will have a significant impact. The next boom will not be the same kind of cycle that we saw in the 1990’s. It will be a competition along gasfired, coal-fired, nuclear and maybe some wind, but
whichever fuel prevails will be the key to who benefits most from the next boom.

Possible Unexpected Turns

MR. MARTIN: You anticipated my last question, which is that if this were a presidential election, the commentators would be asked, before the results come in, what should television viewers watch for tonight? What one or two assumptions are key to the current projections that, if they turn out wrong, could turn the world upside down? Art Holland, let me start with you.

MR. HOLLAND: I would keep a close eye on what happens in the legislature with environmental controls. Most of our pricing projections today are based on the expectation that something close to the Imhofe “clear skies” initiative will pass Congress with the Environmental Protection Agency continuing down the same path on which it embarked last year. That means that power companies will be under orders to reduce NOx and SO2 emissions, and possibly some mercury, but nothing as dramatic as what you see in some of the other competing bills from Senator Jeffords or Senator Carper. If you see something akin to Carper or Jeffords signed into law, which we don’t expect, but if you do, then you are likely to see wholesale retirements of existing power plants. You will see a need for immediate construction of new power plants. And under some of the terms of the Jeffords bill, you would probably see construction of new nuclear facilities because those are the only power plants that would be able to comply easily with the new emissions limits. So, the short answer to your question is keep an eye on what type of environmental legislation comes out of Washington.

MR. MARTIN: If a Democratic administration replaces the Bush administration in the next election cycle and signs the US up to the Kyoto treaty, would that also be a factor that would speed up the recovery?

MR. HOLLAND: Very possibly because CO2 is extremely difficult to mitigate. We would have to reset our thinking on the need for new plants in light of the potential for a large number of retirements.

MR. MARTIN: Mark Griffith, what should bankers sitting over in Europe, but financing power plants in the US, keep an eye on? What are important assumptions in these projections that could change?

MR. GRIFFITH: I agree with Art that one of key signposts will be environmental regulation. It affects not only the timing, but also the type of resources that will be built in the next round and the type of resources that are retired. The other signpost for which bankers should be looking is how many liquefied natural gas terminals get permitted and built in the United States or in areas adjacent to the United States that can serve the US market. On the one hand, if we succeed in developing even a fraction of the 40-plus LNG 
terminals that are under development, that will have a material impact on natural gas prices and change the dynamic as to what type of resource is most economic in terms of new generation capacity. On the other hand, if none of the LNG projects is successful, then the gas price forecasts that we have been using have gas prices at too low a level, and the dynamic will shift in the other direction.

MR. MARTIN: How many new LNG terminals do current forecasts assume?

MR. GRIFFITH: Probably fewer than 10 new terminals out of the 40 that are under development. With 10 new terminals, LNG will no longer be the marginal supplier and will not set the price. The gas price will be set by the new marginal suppliers from frontier sources like offshore gas and newer fields in Canada and Alaska. The price may be something in the order of magnitude of $4 an mmBtu. 

MR. MARTIN: So if more than 10 LNG terminals are ultimately built, then gas prices will be lower than
expected. I don’t know if you are projecting gas prices to decline in any event?

MR. GRIFFITH: Our projection is gas prices will decline in the next four to five years in response to  development. We think that there will be a supply response. 

MR. MARTIN: With what consequence? 

MR. GRIFFITH: The consequence of lower gas prices than expected is a shift in the balance between gas-fired resources and coal-fired resources. Cheaper gas squeezes that coal-to-gas spread and makes it a little harder to justify the coal plants.

MR. MARTIN: Lower gas prices than expected would mean a different mix of new construction, but would they mean a change in the total volume of new construction?

MR. GRIFFITH: They would affect the mix rather than change the absolute numbers.

MR. HOLLAND: We assume in our power projections and electricity and gas price forecasts a certain amount of LNG being available to the market. I can’t tell you off the top of my head the number of terminals. However, I will say that making LNG a prominent and important aspect of our energy future is extremely troubling to me from a national security perspective. It is troubling to me that what was once
thought to be a fuel that we had in abundance in the United States will now have to be imported in large quantities from places like Indonesia and Nigeria. 

MR. MARTIN: Steve Dean, what would be an important change in the base assumptions that forecasters are making today?

MR. DEAN: I would echo what the others have said. A significant change in environmental regulation or a significantly larger or smaller number of LNG terminals from what we have assumed would upset the price forecasts. The other big change in assumptions would be if the United States were truly to take a position that it is going to reduce reliance on foreign oil. It would have a tremendous impact on the power industry.

MR. MARTIN: What effect would it have on the pattern of power plant construction in the US?

MR. DEAN: The United States has oil-fired power plants that run during peak periods. Those plants would be dropped from the system almost immediately. More effort would also be put into developing alternative domestic sources of energy and would have repercussions for the electric utility industry.

MR. MARTIN: You would have a different mix of new power plants, but no change in the overall capacity?

MR. DEAN: Right. Much different types and much different technologies. Our industry ranks today as one of the lowest industries in the United States in terms of R&D funding for new technologies. Most of the R&D work today is funded by the federal government. Let me make one other point: I think we are at a fragile stage in the rebounding of the power industry. Anyone who rushes to take advantage of rising prices or margins by adding new capacity is taking a pretty bold step. He would be taking a fair amount of risk. There are a lot of unknowns as one moves three, five or 10 years into the future. 

MR. HOLLAND: I think the days of estimating what the price of electricity will be in July 2010 are gone. The industry is a lot smarter today, and what forecasters do today is give decision-makers a range of  confidence bands around our expectations for future commodity prices so that they can see how much uncertainty is embedded in the estimates.