The Outlook For Electricity Demand
James Turnure, director of the office of energy consumption and efficiency analysis in the US Energy Information Administration, spoke to Keith Martin of Chadbourne at the Infocast projects & money conference in New Orleans in January about the outlook for electricity demand and wholesale electricity prices in the United States. Before joining the US government, Turnure worked for Xcel Energy and Pacific Gas and Electric. The following is an edited transcript.
MR. MARTIN: I have often thought how much easier life would be if we worked in an industry where there is rapid growth in demand for the product we produce. That has not been true recently about electricity demand in the United States. At what annual rate is demand for electricity increasing?
MR. TURNURE: It used to increase at a faster annual rate than the rate of economic growth. However, our current long-term forecast is that electricity demand will grow by 0.9% a year while the economy will grow at around 2.4%.
MR. MARTIN: Yet that is up from the annual growth rate over the last decade, which was only 0.7%. Is the higher growth going forward — 0.9% a year — entirely due to expected economic growth?
MR. TURNURE: By and large, yes. Our macro-economic forecast comes from external providers. We interact with them, and we have a macro-economic group, but we don’t try ourselves to forecast business cycles or external shocks. We are more focused on trends.
There is a general trend of industrial growth fueled by shale gas.
MR. MARTIN: How does US growth compare to growth in other countries?
MR. TURNURE: Table 1 shows growth rates outside the US. Japan, Europe and the United States have the lowest growth among OECD countries. The areas with fastest growth are China, India and Latin America.
Projected Increase in Central Station Generating Capacity
Other Latin America
Source: International Energy Agency
MR. MARTIN: I should point out that these are not the US government’s numbers, but data that we pulled from the International Energy Agency in Paris. Developers looking at the chart and trying to decide where is the best place to put dollars should take into account the small scale of some of these markets.
MR. TURNURE: There is an overwhelming urbanization trend in most of the world, but especially in Asia. The developing markets are starting to become reasonably large, but unless it is China or India, the market will take a while to reach scale. We are going to see a lot more cities of 10 to 20 million people in the developing world.
MR. MARTIN: I read that the entire demand growth for electricity in the United States the last three years will be offset by the shift to more efficient light bulbs. True or false?
MR. TURNURE: Close to true. If you took demand growth in normal years, it would be false. If you look at the last three years when the economy was struggling, then yes.
MR. MARTIN: What are the most important assumptions behind the forecast of 0.9% annual demand growth?
MR. TURNURE: The rate of macro-economic growth is first. Employment plays a really vital role in energy demand in general. The data series on employment tend not to exhibit gentle changes. There are a lot of cliffs in those data series up and down. We are currently in a very flat employment period. That is ahistorical.
MR. MARTIN: Say again what you are assuming for annual GDP growth?
MR. TURNURE: 2.4%.
MR. MARTIN: What is the second most important assumption?
MR. TURNURE: Number two is the pace of investment in technologies that go into these more dispersed demand sectors. That is very hard to analyze. You have to think about the rate of R&D that goes into appliances, HVAC and lighting being the dominant residential applications, but also things like supermarket refrigeration and some of the bigger commercial applications. Industrial energy efficiency has been an after-burner item, but it is starting to show results. These are more sources of uncertainty than they are likely to cause big upward or downward adjustments in the demand forecast. The end users are widely dispersed so that you can have a breakthrough in an area and it would only affect a small portion of the demand.
MR. MARTIN: Many people think there could be a surge in demand as the public switches to electric cars. What does the US government think?
MR. TURNURE: We are an independent agency, so our view is not necessarily that of the current administration. At this point, we have a fair amount of electrification in autos, but it is almost all hybrids. We expect eventually to see less than half of new vehicle sales made up of cars that use conventional gasoline. However, very few vehicles currently in use are dedicated electrics. There is actually more activity in natural gas vehicles than in electric vehicles. Long-haul trucking companies have started using LNG, and it is the first time that an alternative fuel has made it into our reference case in simple economic terms. In the transport sector fuel mix, we see gasoline peaking and then declining. That is a significant break with past trends.
MR. MARTIN: The growth of rooftop solar changes how homeowners get their electricity. How much growth do you expect in this sector?
MR. TURNURE: We expect dramatic growth in the next few years. Utility-scale solar continues short-term growth thanks to state renewable portfolio standards and then flattens out until 2035 when more capacity is added. Rooftop PV will have a large growth spurt until the investment tax credit expires at the end of 2016. This demonstrates that while we do not consider rooftop solar to be economic at typical installation costs today, it is close enough that the investment credit makes a huge difference.
MR. MARTIN: If the government believes that the rooftop solar sector will basically flatline after 2016 when the investment tax credit expires, then isn’t that a strong argument for extending the investment credit?
MR. TURNURE: The investment credit was a pretty special idea. There had been the earlier annual production tax credit taken against each kilowatt hour of electricity produced. To replace it with a tax credit that the owner of a project takes up front and as a percentage of the capital cost of the project was a onetime experiment. Congress will have to evaluate where to go with that. If we were talking about the production tax credit, you would say, based on history, that it has always been renewed, but the investment credit has not had that history yet. We cannot assume an extension in our forecast.
MR. MARTIN: Your forecast in Table 2 shows rooftop solar growing at a rapid pace though 2016 and then not growing at all again until 2035. What do you expect to happen in 2035?
MR. TURNURE: Mostly technological changes that bring down the cost. However, two other factors that will lead to more growth are state RPS targets in the long run, and we will also reach a point where demand growth by itself starts to pull some additional kilowatt hours.
MR. MARTIN: Low natural gas prices are leading to growth in industries that depend heavily on natural gas. Could that help with electricity demand?
MR. TURNURE: It definitely helps with demand. However, it is important to understand that the shale gas boom will boost domestic industrial competitiveness, but we see this as a short-run story that is less important over the longer term because that competitiveness eventually gets washed away again. In our baseline forecast, the industrial sector growth is higher this year than it was last year. It drags quite a bit of electric power growth with it.
MR. MARTIN: Project developers have been watching planned retirements of coal-fired power plants, figuring they could fill in that capacity. What retirements are you expecting and when?
MR. TURNURE: We increased the number of retirements we expect in the near term in our latest forecast in Table 3. We think the air regulatory picture will be clarified somewhat for the owners. The next time any of these owners has to make a major investment for compliance reasons or because the aging plant needs work is when the plant shuts down. The need for such spending tends to pull retirements forward in time. Instead of a small investment being a bump in the road, it becomes the end of the line.
MR. MARTIN: Your 2014 forecast shows fewer retirements this year than you expected even a year ago.
MR. TURNURE: This is more a consequence of how we think the market is responding to nearly level demand. Some aging plants will be retained for reserve margin purposes. Are you really going to build new capacity in a period of weak demand growth? That depends on the specifics in the regional market in which you are operating.
MR. MARTIN: Where do you expect the need for additional generating capacity to be greatest?
MR. TURNURE: Every summer, the National Electric Reliability Council estimates what will happen to reserve margins in the different regions. New York, Texas, the Midwest and California all have pretty tight reserve margins. If you lose any plants in those areas, you are going to have to replace them.
Gas and Power Prices
MR. MARTIN: Natural gas prices are a big factor in the US generating mix. What is the government projecting for gas prices, at least for the power sector?
MR. TURNURE: The shale gas story is important, but the big question is the long-run cost for shale gas development. Given how small scale and relatively new a sector it is, the cost is hard to predict. Historical trends suggest we are moving toward $7 or $8 an mcf over an extended period. A lot of people would have thought a few years ago that you would never have gotten under $7 or $8 for a significant period of time. There was a time around 2005 when the Energy Information Administration would have needed to assume in our forecasting both LNG imports and an Alaska pipeline even to maintain prices around the $8 level. Now, without either one of those things, we have prices staying under $8 for the next 20 years.
The ratio of coal to gas is an important indicator of competitiveness. Last spring, we saw more gas generation than coal in the US markets for the first time ever. Despite this, coal should recover a little bit of its edge back in the mid- to longer term. That is one reason why the coal-fired power plants that do not retire in our forecast are heavily used.
MR. MARTIN: Given the government’s interest in reducing greenhouse gas emissions, will it allow coal to come back as a fuel? Is this a realistic forecast?
MR. TURNURE: That is a big uncertainty. The full forecast we release in the spring 2014 will include a lot more scenarios. It will include some carbon tax scenarios. Some policies assumed in the forecasts are directly targeted incentives and penalties to reduce emissions which, if they were comprehensive, would look somewhat like a carbon tax. In the meantime, some coal-fired power plants will retire, but the remaining plants will generate more. So we have an essentially level coal share of the market going forward.
The flatter the demand growth gets, the less you need renewables because most state RPS standards are volumetric. If you build fewer renewables, then there is more room for natural gas to eat that remaining market share.
MR. MARTIN: US capacity additions in October 2013, the most recent month for which we have data, were 72% solar. Do you think solar will be able to put up these kinds of numbers through 2016 when the investment tax credit expires?
MR. TURNURE: I find that pretty unlikely. Maybe they did not correct for capacity utilization.
MR. MARTIN: You expect biomass to take off along with solar. For the last two decades, government officials in this country and Europe have been saying that they expect biomass to be the next big thing. It never happens. Why not and why believe it will happen this time?
MR. TURNURE: Biomass can serve as a base-load resource. When people are doing policy and forecasting, there is a big interest in getting beyond the intermittent resources in wind and solar and looking at base-load resources. That is why hydroelectric has been the dominant renewable resource for all these years. Biomass is the second largest source of renewable power and has been for a long time because of its role in the pulp and paper industry and in other associated industries. Beyond that, it has been a question of how people run their state RPS standards and eligibility. Biomass has a pretty heavy upfront capital requirement, and the power plants tend to be larger-sized systems. The research and development is also quite expensive. You can build a prototype wind turbine for
$1 or $2 million, but a biomass plant might cost $250 million for just a half-size demonstration unit.
MR. MARTIN: What do expect for wholesale power prices over the next few years?
MR. TURNURE: Many retail customers ask why their retail rates are not falling in line with natural gas prices. The reason is that even in competitive markets like the PJM system in the mid-Atlantic region, the utilities let out the energy portion for load in chunks; so those tranches take a while to pick up lower gas prices. Lower gas prices will eventually be reflected in rates, but it takes time to see the effects. The energy component of rates is not that big anyway. People forget that the transmission and distribution portion of end-use rates is pretty stable, if not increasing, because every time there is a big storm or something falls apart, the regulators have to increase rates to rebuild the transmission and distribution system. That’s why we continue to see an upward trend in power prices overall.
Wholesale prices tend to move in the same direction as retail prices.
MR. MARTIN: Your 2014 forecast is for a rise of 1% a year in US electricity prices, but a little higher in the areas you said need more power: New York, New England, Texas. Wholesale prices tend to follow natural gas prices which are projected to rise in the forecast by 3% a year. Electricity prices are rising, but they tend to lag natural gas.
MR. TURNURE: We have pretty level demand, but a bit more money will flow through the system year on year.