Think there are no disruptive generation technologies on the horizon? Think again.
By Yorgos Papatheodorou, CH2M Hill
Three years ago, I presented a paper at POWER-GEN International called “The Economics of Generation Technologies: Present and Future.” Then, our firm’s process of interviewing dozens of industry executives revealed that the conventional wisdom could be summarized as “no technology available today has the potential of becoming transformational or disruptive in the next five to 10 years.” An exercise in scenario planning (using assumptions based on technology, regulations and fuel prices) proved the conventional wisdom correct. However, using different assumptions about technology adoption, greenhouse gas regulations and fuel prices showed that in 20 years’ time things could be different, making some renewable generation technologies quite attractive.
It is time to revisit those results. Technology and regulations have changed. So have fuel prices. In 2006 we completed another Strategic View research report, which covered the electric power, oil and gas and unconventional energy industries, as well as manufacturers who either use energy or produce equipment with energy applications. In the current environment the findings are quite different.
This paper summarizes the current Strategic View findings. It then revisits some of the scenarios presented in 2003, using the latest assumptions on overnight capital costs, O&M costs and heat rates of different generation technologies from the U.S. Energy Information Administration (EIA). The cost per megawatt-hour of the alternatives is given first for plants ordered in 2005, then in 2025. Two different assumptions about technological progress give quite different results. The issue of greenhouse gas regulation is dealt with through two alternative scenarios: carbon sequestration and carbon allowances or an equivalent carbon tax. All scenarios are repeated with a high and low cost of coal and natural gas.
The results reveal substantial variability in the cost per megawatt-hour. Even solar photovoltaic (PV) generation could become competitive in 20 years under some assumptions. Nuclear, hydro, wind, geothermal and biomass remain competitive through every scenario. Of course, each has its own limitations: public opposition, lack of high quality resources, intermittent and unpredictable production and so on. Predictably, any type of greenhouse gas regulation hurts all fossil fuel technologies, but carbon sequestration mandates penalize gas-powered plants more than allowance trading or carbon taxes. And the price of natural gas clearly affects the balance enormously.
A Changed World
The power generation industry is being affected by forces far different than three years ago. Instead of a collapsing merchant market, the focus is now on high and volatile natural gas prices. The industry needs more coal-burning capacity but also must deal with increasingly stringent environmental requirements. It is investing in new ways of burning coal, with integrated gasification combined cycle (IGCC) the most prominent. More conventional technologies (pulverized coal and circulating fluidized bed) are being enhanced with supercritical steam and new emissions-reducing technologies.
The industry is also moving toward increasing numbers of nuclear power plants with improved reactor designs. The U.S. government, through the Energy Policy Act of 2005, substantially increased incentives to kickstart new nuclear power plant construction. More efficient turbines for both steam and gas are increasing the conversion rate of heat to electricity while cutting generation costs.
Finally, in response to state regulatory pressures, renewable technologies such as solar and wind are seeing more investment. Even with the current cost of fossil fuels, renewables struggle to be economically viable without tax incentives. However, as these resources are developed the cost of production should begin to fall, increasing the potential for widespread adoption.
Comparing Costs
Such costs are compared in Table 1, which gives all the underlying assumptions.
- Overnight capital costs and fixed O&M costs are given per kilowatt. Both come from the EIA1. Both numbers were checked against utility operating statistics from the EIA for conventional technologies.
- Heat rates determine efficiencies of thermal plants and fuel cells and are also from the EIA.
- Capacity factors are based on long-term averages, not maximum practical utilization. Costs are sensitive to capacity factors, since the higher the utilization, the lower they work out to be per megawatt-hour.
- All prices and costs are in constant 2005 dollars.
In our calculations, capital costs are amortized over 20 years at a 6 percent interest rate. A shorter amortization would increase capital costs, as would a higher interest rate. To convert capital cost per kilowatt to capital cost per megawatt-hour, we find the yearly capital cost per kilowatt and divide it by the number of hours the plant is expected to operate in a year. This equals the maximum number of hours in a year (24 times 365), times the capacity factor. We used typical capacity factors for conventional plants and made assumptions about alternative technologies.
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The fuel cost for coal and gas is the price of fuel (in dollars per million British thermal units, Btu), times the heat rate (Btus needed to generate a kilowatt-hour of electricity), divided by 1,000. Thus the fuel cost depends on the plant’s thermodynamic efficiency (heat rate) and the price of fuel. We have run a full set of scenarios assuming high fuel prices ($4/MBtu coal and $10/MBtu gas) and low fuel prices ($3/MBtu coal and $6/MBtu gas). Hydrogen for fuel cells is assumed to come from natural gas reformers and depends on the price of gas and a fixed component.
The low and high fuel scenarios based on Table 1 are shown in Figure 1. Gas-fired plants made perfect sense at $2.50 gas: the plants had low risks, a benign environmental profile, low capital costs and quick turnaround times. Because they are sensitive to fuel prices, however, the economics of gas-fired plants are vastly different now, with volatile natural gas prices well above the levels power companies were used to even three years ago. Running combined cycle plants at a high utilization, or charging high prices for peaker combustion turbines, can make the economics more attractive, but gas cannot compete on economics alone against many alternatives. Similarly, distributed generation cannot compete on economics alone, a fact that persists through every scenario. Instead, this technology is attractive for other reasons.
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Both conventional coal and IGCC are quite competitive. The problem is finding sites, overcoming public opposition, tying up capital for several years and dealing with the risk of future greenhouse gas regulations. Still, the surge in planned coal capacity is a testament to the changed economics.
Newest-technology nuclear plants would be competitive, which explains why several proposed plants are at least being talked about. Of course it all depends on the regulatory framework, which can easily increase delivery time cost and risk far beyond what is technically feasible. In addition, nuclear power remains unpopular in many places and the long-term future of waste storage remains unsettled.
Hydro, geothermal, wind and biomass are also competitive with today’s technology and in both price scenarios. All of these technologies, however, have problems to one degree or another finding suitable, high-quality resources and overcoming local opposition to siting.
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PV will not be cost-effective if capital costs are not brought down by a factor of roughly five. Solar thermal has a lower hurdle to overcome: a drop in capital cost by a factor of three would make it cost competitive.
With fuel cells, both capital costs and fuel costs are high. Since we have assumed that fuel cell generation uses hydrogen reformed from natural gas, fuel cells can never compete with a combined cycle plant. Other sources of hydrogen fuel, including electrolyzing it with renewable electric power, would make sense for two specialized uses: as a way to store energy from intermittent sources and for powering vehicles.
Minimum Technological Progress
For its long-term forecasting models, the EIA assumes that power plant capital costs and heat rates do not stand still. It has adopted the technical progress methodology pioneered by the International Energy Agency. A 2000 white paper2 measured technological progress in the form of declines in capital cost per megawatt of generation capacity, and found that a negative exponential relationship exists between this cost and the total cumulative amount of capacity installed. In other words, with each doubling of cumulative capacity the cost falls by a fixed amount, which we can call “x”. Fitting a curve to PV capital cost and cumulative sales data gives an estimated “x” of 18 percent. This relationship was found to hold with most technologies, both mature and emerging; but some technologies have a much lower “x”-the “progress” quotient-than others.
Because the cumulative installed capacity of alternative technologies is so low, plenty of potential exists for their cost to fall. A doubling of installed coal capacity worldwide would entail adding about 1,000 gigawatts (GW). By contrast, a doubling of PV capacity would mean about 7 GW of new capacity3. California alone could add half of that if the latest mandates have concrete results.
However, the EIA has decided to be cautious in using this methodology, specifying in its model conservative minimum declines in capital costs. We first use the EIA technology assumptions, which also include drops in heat rates (as thermal technologies become more efficient). We call these assumptions the “minimum” technological progress scenario.
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Figure 2 shows the low and high fuel price scenarios for 2025. Again, the incremental effect of high fuel costs is represented by the top element in the stacked bars. Clearly the gap between conventional and solar technologies is reduced by the “minimum” technology assumptions, but not enough to make them competitive. Meanwhile, because conventional technologies progress (become cheaper) faster than wind, the latter slips from its competitive position. Under the high fuel assumption, solar thermal becomes competitive with gas combustion turbine. Otherwise, the results from the current technology scenarios do not change much.
Fast Technological Progress
The assumptions about technological progress behind the minimum scenario are reasonable, but could be called too conservative. Assuming progress rates consistent with the International Energy Agency analysis4 and rates of capacity doubling more in line with the experience of the past 10 years, much steeper drops in capital costs result (Table 3). It is actually possible that the capital cost of PV could drop by a factor close to four over 20 years.
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The results of this scenario are shown in Figure 3. The moral of the story in these scenarios is that the capital cost of alternative technologies over a long period of time is hard to predict and sensitive to rates of technological progress and rates of adoption. It is not inconceivable that in 20 years wind generation could be cheaper than gas or even coal and PV competitive with fossil fuel generation, as well as substantially cheaper than solar thermal. By contrast, fuel cell generation, even under the most optimistic technology scenarios, remains relatively expensive because of fuel costs.
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Greenhouse Gas Scenarios
The scenarios so far have taken no account of the effects of CO2 emissions regulations. Such regulations, whether they are command-and-control (carbon sequestration mandates) or market-based (carbon allowance trading or carbon taxes), would further shift the cost balance in favor of nuclear and renewable technologies and would have the biggest effect on coal plant competitiveness.
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Unlike three years ago, the EIA now has estimates of the capital cost and O&M of sequestration and the declines in efficiency (higher heat rates) resulting from it. These estimates remain tentative, especially since the cost, effectiveness or environmental impact of carbon dioxide disposal methods are unclear. Still, it is instructive to run these scenarios and compare them with the alternative, market-based approach. (Conventional coal is not presented here because we have no sequestration cost estimates.) Assumptions are given in Table 5 and results are shown in Figure 4.
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Carbon allowance markets are still not well developed, so we assumed a price that has held on average in Europe: approximately $24 per metric ton, which translates into $1/MBtu for coal and 14 cents per MBtu for natural gas. Equivalent carbon taxes would have the same effect (on cost of electricity, not power company finances): they would increase the cost of fuel by the same amount. They both add directly to the fuel cost of conventional coal plants and affect IGCC, gas and fuel cell generation (as long as the latter uses fossil-fuel-derived hydrogen) to a lesser extent. The capital, O&M and heat rate assumptions are unchanged from Table 4: the only thing that changes is fuel price. The results are shown in Figure 5.
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Greenhouse gas scenario analysis shows coal still to be viable, albeit less competitive against nuclear and renewable technologies. Additionally, a carbon tax or allowance at $24 per metric ton has the same effect on IGCC cost as a sequestration mandate; this supports the idea that current allowance prices are in the right ball park. The same cannot be said about gas: sequestration mandates would hurt gas plants much more than a tax or allowance, because the carbon equivalent cost of the market-based approach is much smaller than for coal (given the low amount of CO2 per MBtu produced by gas). By contrast, sequestering CO2 from a gas plant is almost as costly per megawatt-hour as for coal.
Viewpoint Reconsidered
The prevailing opinion in the electric power industry three or four years ago was that there were no disruptive generation technologies on the immediate horizon. This has clearly changed.
Even using assumptions based on current conditions about technology, regulations and fuel prices, several cost-effective renewable technologies exist: wind, geothermal, hydro and biomass are all alternatives that will not require large subsidies. Each has the “usual” problems: some combination of siting, distance from load, resource availability and unreliable/intermittent supply. Solar photovoltaic power is so far from being cost competitive that only large subsidies or mandates will speed up its installation. Solar thermal is closer to a reasonable cost range with high fossil fuel prices.
Changing technology assumptions was found to change the conclusions. For example, rapid adoption of solar technology could reduce the capital cost over a period of 20 years, so much so that even photovoltaics could become cost-competitive by 2025.
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CO2 regulations would substantially affect the comparative costs of generation technologies. Any regulation would make coal and gas less competitive and work in favor of nuclear and renewable energy. However, different policies have different results. A command-and-control solution (sequestration mandates) would not only cause more disruption by forcing older coal plants to shut down, but would also impose a much heavier burden on gas-fired plants than the market-based alternative. Market-based solutions include allowance trading and carbon taxes. As long as they are the same per ton of carbon equivalent, they have the same effect on the cost of generation. An allowance or tax of $24 per metric ton would have the same effect on the cost of IGCC electricity as a sequestration mandate.
Meanwhile, the economics of gas plants depend so heavily on natural gas prices that a 20-year price forecast is necessary to run proper scenarios. Because the range of forecasts and the expected volatility are both higher than three years ago, it is safe to say that gas no longer holds all the cards. The gas price outlook has already upset the balance in favor of coal, nuclear and renewable energy. The scenarios prove it.
Notes:
- Table 38, Annual Energy Outlook 2006, p. 73.
- Experience Curves for Energy Technology Policy, International Energy Agency, Paris, 2000.
- Renewables in Global Energy Supply: An IEA Fact Sheet, International Energy Agency, Paris, Nov. 2002.
- Experience Curves
Yorgos Papatheodorou is Senior Project Manager with CH2M Hill Business Location and Economic Development Consulting.