The Intergovernmental Panel on Climate Change has made clear that climate change is a worldwide issue imbued with unparalleled urgency. Naysayers remain, but the weight of evidence today indicates that we need to deal with it—collectively and quickly. At the same time, it’s clear that the need for new power generation capacity in the United States will continue growing. Efficiency and the recession will reduce the rate of growth, but the inexorable forces of economic growth; general electrification of the economy; aging power infrastructure; new technologies (e.g., electric vehicles); and population growth will stimulate the need for additional sources of electricity.1 Even during recessions in the United States in the 1980s, the 1990s and earlier this decade, the demand for electric power dipped only temporarily before recovering strongly to maintain a long-term growth rate of 2 to 2.5 percent.2 While some countries continue to pursue business-as-usual resource options,3 often involving coal generation, it’s clear that for both developed and developing countries, the challenge revolves around the imperative to sharply lower emissions of greenhouse gases (GHGs), while also meeting the growing need for power.
But there is another dynamic at work as well—the dynamics of the pocketbook. All the legislation proposed to deal with climate change—whether called “cap and trade” or “carbon tax,” of which many proposals target emissions reductions of approximately 80 percent by 20504—would increase the cost of power.5 Moreover, this impact on consumers will differ depending on the type of regulatory framework (e.g., cost-of-service or competitive market). As consumers struggle with economic challenges, regulators and legislators naturally will seek to avoid significant increases in energy costs, since higher energy costs, particularly for fossil fuels, ripple throughout the economy, not just at the gas pump or the electricity meter. This is a compelling generational challenge—what’s necessary in the long run (the mitigation of climate change and its impacts, and the creation of green jobs) might not be so good in the near term.6 How much of a hit should consumers be expected to take to mitigate the impacts of GHGs?
In the midst of this dichotomy—this inter-generational challenge—utilities and their regulators (and occasionally their legislators) must deal with a multi-billion-dollar, multi-faceted question: How can we best satisfy the need for a reliable power supply, at a reasonable price, with acceptable environmental impacts? In the process, what happens to the existing capacity, particularly the 330 GW of coal capacity that today provides about half of our electric power? However necessary CO2 reductions may be, as legislation and policies are being considered to force these reductions, we also need to understand the implications of this legislation on electricity consumers.
There are many signs that policy-makers, industry and the public are taking the issue of climate change seriously:
• Individual utilities are showing strong leadership on the GHG reduction front;7
• The Energy Independence and Security Act of 2007 (EISA) and the American Recovery and Reinvestment Act of 2009 (the stimulus package), have locked in non-trivial GHG reductions and energy savings;8
• Federal regulatory initiatives have reduced GHGs (e.g., the renewables fuels mandates, CAFE standards, lighting and appliance standards in the EISA of 2007);
• State GHG-reduction and renewable programs have mushroomed;9
• Regional GHG efforts (e.g., the Regional Greenhouse Gas Initiative, Western Climate Initiative, and Midwest GHG Reduction Accord) are flourishing;
• There is strong international action to reduce GHGs (the European CO2 trading market; and the Asia-Pacific Partnership to collaborate on climate-friendly approaches in seven countries representing over 50 percent of global emissions;
• With greater climate awareness, more Americans are warming up to the idea of driving fuel-efficient cars, including hybrids, and many are driving less; and
• EPA’s recent endangerment finding now makes the prospect of CO2 regulation under the existing Clean Air Act a real possibility, and serves as a strong incentive for Congress to find a legislative solution to the GHG issue.
With all this activity, there isn’t yet an over-arching national plan for how to satisfy both our energy needs and deal with the climate crisis at a reasonable cost. This is a complex undertaking, and the challenge falls to the Obama administration, requiring both national leadership and international cooperation. Congress is considering national legislation to limit GHG emissions in the United States next year, which could substantially affect the cost of power from carbon-containing sources, and the more stringent the emissions cuts required, the greater the impact. Issues such as the allocation of emission allowances and the role of offsets will significantly influence the cost of such a policy. The control, trading or taxing of GHGs clearly will affect the owners of both existing generation and new capacity, as well as all electricity consumers, and the economy as a whole.
What will happen to existing capacity under legislation that controls CO2 emissions? Under all the proposed versions of CO2 legislation, it will take several years before the necessary regulations are promulgated and a cost for carbon is added to the cost of generation. That is, if CO2 legislation is passed, the U.S. EPA or other agencies will need to write the regulations to implement it, and provide a transition period for compliance. Thus, if there is CO2 legislation this year, carbon emissions likely will begin incurring a cost in the 2013 to 2015 time frame. After that point, the additional cost of emitting carbon will depend on the strategy and approach to compliance that the plant owner takes. Some compliance options with regard to the existing fleet of power plants could include:
• Purchase Allowances: Continue to generate as before to meet consumer needs, and pay to purchase all allowances not granted to the plant owner under the legislation for all tons of CO2 emitted from existing fossil plants;
• Purchase and Reduce Moderately: Reduce CO2 emissions through a combination of purchasing allowances; cutting back or shifting production using environmental dispatch; co-firing or retiring some of the smaller, older units. This strategy could apply to all plants or just the most highly emitting ones.
• Aggressively Reduce or Eliminate: Phase out the majority of CO2 emissions through an aggressive program of new technology and substitution, including non-emitting alternatives such as renewables, nuclear and end-use efficiency, and retrofitting existing coal units as well as developing new coal capacity with carbon capture and sequestration.10
The most cost-effective choice among these options will depend on the details of the GHG legislation and regulations, and on the plant owner’s mix of capacity and cost of compliance.
From a plant owner’s perspective, a key question is whether existing coal plants will be dispatched less often if they are substantial CO2 emitters. Lower production from coal plants, for example, would increase the generation from other types of plants, significantly influence the level of capital investment that makes economic sense, and affect operations and maintenance required over the entire generation portfolio.
What is the break-even point for CO2 costs, where it becomes uneconomic to operate existing coal plants? ICF’s market models suggest that even though such legislation will increase the cost of generation from existing fossil-fuel plants, CO2 prices at moderate levels (such as $25 per ton in 2006 dollars) will not affect their dispatch order; that is, they still will be cheaper to operate than other alternatives. This suggests that until utilities need to make decisions on the next increments of capacity, the relative utilization of their plants isn’t likely to change, if carbon prices are moderate and gas prices remain at or above $7/MMBtu11(see Figure 1).
It’s important to look at all the costs of plant operation in conducting this analysis. Figure 1 shows all these costs, including: fuel and variable O&M costs; NOx and SOx expenses;12 and finally, under the CO2 control case, CO2 costs. For coal plants, every $10/ton adds about 1 cent per kilowatt hour on a marginal (dispatch) cost basis, so a $25/ton cost adds 2.5 cents/kWh. For gas-fired combined-cycle plants, on the average every $10/ton adds just over 0.4 cents/kWh to the marginal dispatch cost, so a $25/ton cost adds a bit more than 1 cent/kWh. CO2 cost additions of this order of magnitude will increase the cost of generation, but do not change the relative order of the cost of dispatching these plants—with the exception that the uncontrolled coal unit is pushed out.
As CO2 prices rise, existing coal plants become less attractive to operate. Specifically, above about $30/ton for CO2, with natural gas prices of $7 to $8/MMBtu, coal’s competitiveness in the dispatch order drops dramatically. Existing coal plants likely would provide about 2 million GWh in 2030 at prices up to that level. But should CO2 prices reach $60/ton, production from existing coal plants would fall about 40 percent to about 1.2 million GWh, as existing plants are retired in increasing numbers. At $80/ton, production from existing coal plants in 2030 would fall off the cliff by 85 percent, perhaps just reaching 300 million GWh, if such plants generate at all by then. If gas is less expensive, this conclusion is even stronger.
In sum, what happens to CO2 prices, whether allowances are granted to existing coal facilities for an extended period to cover their emissions, and what happens to any allowance allocation if a unit retires, all make a huge difference in the mix of generation from existing plants, and the cost of that generation as well. If these plants dispatch less, this in turn affects the amount and type of new capacity required.
For new generation plants, there also are key break points in evaluating the cost impacts of carbon regulation. However, the impact on the types of new capacity that get built is more dramatic than the impact on existing capacity, as the levelized costs of technologies tend to be grouped more closely together than existing plants, so the CO2 price has a relatively larger impact. Baseload options and wind facilities have the most impact on providing new sources of power, and they would be the most affected by CO2 prices.13
The cost of the new plant clearly is a key factor in making the best decision on plant development. Construction and commodity costs have escalated sharply in the past few years (i.e., the cost of steel had risen about 70 percent until the early fall of the past year, although it has fallen more recently as a result of the world-wide recession).
The data and projections in Figures 2 through 5 combine into one single levelized figure ($/MWh) all the elements of such costs, including: the capital and financing cost of the plant; the cost of the fuel; the cost of O&M; and the cost of traditional emissions controls (SOx and NOx). For example, Figures 2 indicates that combining all these factors, the current levelized average cost of building and operating a new combined-cycle plant over its lifetime is just under $80/MWh, while the levelized cost of building and operating an uncontrolled (for CO2) coal plant is about $70/MWh (in 2006 dollars). This suggests that with no carbon controls or regulatory objections, coal plants would be built ahead of gas from a purely economic perspective. However, as the price of CO2 rises, the cost of generation from coal increases faster than the cost of generation from gas, since coal’s emissions of CO2 are higher due to both the carbon content of the fuel and the relative efficiencies (heat rates) of the units.
Figure 2 also shows that the break point between building coal and combined-cycle plants (under the model’s expected case) is about $15/ton. The higher the cost of CO2, the greater the gap, such that at $50/ton of coal, it’s about $13/MWh cheaper, or about 10-percent cheaper, for a plant owner to build and operate a gas plant over its lifetime, assuming a levelized price of gas of $7 to $8/MMBtu.
Figure 3 adds other generation options, including the IGCC plants (with carbon capture), nuclear plants and wind generation. As before, all plant types have a different starting point for the levelized cost of power plant construction and operation—with the levelized cost of IGCCs the highest of them all—but the slope of the cost line depends on their carbon footprints. Thus, the cost of nuclear and wind do not change as the cost of carbon emissions rises, while the cost of IGCC with CO2 capture rises only slowly, as we assume 90-percent capture.
Most of the action takes place between about $15 and $40/ton. At the low end, wind and nuclear become more economic than either pulverized coal or combined cycle, and above $40/ton, the IGCC plant is a better economic choice than pulverized coal. At the far right, a price of $55/ton marks the cross-over between combined cycle and IGCCs, with the latter being the better choice at CO2 prices above that level.
Naturally, these figures are a moving target, as the cost of building and operating plants is in flux. No one has built a new nuclear plant in the United States in decades, nor is the cost for commercial deployment of CCS well known. These results must be tailored to each situation, but represent a conceptually strong way to think about the tradeoffs between the cost of generation, GHG regulations, technology and fuels.
Figure 4 shows the implications of a climate bill similar to the legislation proposed—the Dingell-Boucher discussion draft bill—on the capacity additions and the generation mix between now and 2030.14 The results are dramatic in terms of changes in the future mix of power generation, and this also affects the future cost of power.
One not-often-cited, but key element that affects this mix is the allowed level of CO2 emissions offsets. “Offsets” refers to the ability of those required to reduce their emissions to purchase emissions reduction credits from other, uncapped sources, instead of having to reduce their own emissions, if they can make more cost-effective CO2 reductions. Offsets effectively raise the emissions cap, while reducing emissions in sectors and regions where reductions are not required. The analysis modeled both 11 percent and 22 percent offset scenarios—the 22 percent commensurate with the amount of offsets allowed under Dingell-Boucher over time, and the 11 percent with the exclusion of international offsets. Both Lieberman-Warner and Waxman-Markey allow for greater use of offsets, although they have more stringent emissions limits.15 The higher the allowed level of offsets, the greater the flexibility that generation owners have to meet the required targets. This flexibility means that the new megawatts that need to be built is lower, since more existing coal capacity can continue to operate while its owners purchase lower cost allowances using offsets. Further, a higher level of offsets means that there is less gas generation and renewables than in the more restrictive offsets case, but more than in the business-as-usual (BAU) case. Finally, in both cases, there are no new coal plants built without some form of carbon-capture technology—i.e., the existing pulverized-coal technology is no longer built.
This one element of carbon legislation—offsets—would have a major impact on the total amount of new capacity built. At a lower level of offsets, it would lead to more total capacity (about 560 GW by 2030), since utilities and other generators would be compelled to replace aging plants to meet emissions-reduction requirements on their own. With a higher level of offsets, just the opposite would occur, with less total capacity required (about 470 GW by 2030) than in the reference case (about 515 GW). Thus, the swing in capacity built would be almost 10 percent based only on a change in the level of offsets allowed.
The total cost of adding such capacity will make a meaningful difference to consumers. Under the modeled scenarios, the cost of adding new capacity through 2030 would be approximately $1 trillion. Making wise choices about how this capital is spent is crucial for utilities, their ratepayers, regulators and investors. Consumers will feel the difference both in the cost of building and financing the plants, and in the cost of fuel and emissions allowances.
The implications of these capacity choices are far from academic, as the need to plan for new capacity is starting in many regions (see Figure 5). The inescapable conclusion is that legislators in Washington, D.C. need to send a strong signal on CO2 emissions soon to the utility industry, or many of them will have to make decisions on what types of capacity to add to ensure the industry can keep the lights regardless of policy signals. They also will need to quickly implement programs to reduce demand (e.g., interruptible load and time-of-day pricing) in order to buy time. Delays in making these decisions will raise the cost of meeting growing power demands while controlling CO2 emissions, and will absorb more of Americans’ paychecks. Of course, the current recession somewhat delays the need for new capacity, allowing a bit of breathing room for both the implementation of new regulations and the development of new technologies, but a continuing recession is the kind of medicine no one wants to take. Further, the lower demand can give false hope, as economic growth typically snaps back quickly, so the need for new generation capacity in the near term may re-emerge just as rapidly.
The way the power sector is regulated determines largely what the impact will be on consumers. Thus, it is critical to distinguish between what those impacts would be under two different regimes: 1) competitive wholesale markets; and 2) traditional cost-of-service/regulated markets.
In cost-of-service markets, the additional cost of CO2 allowances at plants that use fossil fuels likely will treated in a manner similar to a fuel surcharge. The incremental cost—whatever it is—likely will be passed through to consumers. Many (but not all) traditionally-regulated states have fuel adjustment clauses that allow utilities to include the cost of fuel on consumer bills. Some states oversee fuel purchases to ensure utilities are making them efficiently, but in essence, this cost is one that consumers bear on a dollar-for-dollar basis, with that cost represent-ing an additional component of the cost-of-service ratemaking algorithm. That is, the cost of carbon will impact the average cost of rates by raising the cost of generation that emits CO2.
In competitive wholesale markets, however, if CO2 allowances cost $20/ton, and that increases the cost of generation from natural gas and coal, then whenever gas is on the margin, the price for all generation in the market receives that price. Thus, in competitive markets, the price of CO2 has a more universal effect on all consumers when CO2-emitting sources are on the margin compared to cost-of-service markets.
The DOE’s Energy Information Administration reports that on average, nationwide, the cost of power delivered to residential consumers was about 10 cents/kWh in 2007, including the cost of generation, transmission and distribution. In a cost-of-service state, if the cost of existing coal generation rises 2.5 cents/kWh due to CO2 allowance costs (at $25/ton), and coal provides half of the generation in the United States, this factor alone would increase the cost of electricity by 1.25 cents/kWh, or about $137/year if average residential consumption is 11,000 kWh/year. If natural gas generation provides 20 percent of the need, the cost of CO2 allowances would add another 0.5 cents/kWh, or $55/year, for a total of $192. This is an increase of 17.5 percent in the total electricity bill. Those areas with more coal generation, such as much of the Midwest and Western States, would experience higher increases.
In competitive wholesale states, however, the impact could be less or more. Every hour that natural gas is on the margin, the distribution utilities at wholesale and the consumers at retail will pay the higher CO2-affected cost for all generation, including natural gas, coal, wind, and nuclear. In the hours (perhaps off-peak) when coal is on the margin, the same dynamic is in force—all generation will receive the higher CO2-adjusted wholesale cost of power, and all the energy that consumers buy will cost more as a result. If, on the average, natural gas is on the margin 75 percent of the time and coal is on the margin 25 percent of the time, and allowances cost $25/ton, then the weighted average increase in all kilowatt-hours is 1.375 cents/kWh, which would increase rates by $151, or 13.7 percent. If, however, the split is 40/60 (i.e., coal on the margin 60 percent of the time), the weighted impact would be 1.90 cents/kWh, for an annual impact of $209, or 19 percent. Clearly, the more often coal is on the margin, the higher the impacts on consumer rates and bills, at least until generation owners build capacity that doesn’t emit CO2 on the margin.
Regardless of the regulatory approach, it’s clear that when adding the cost of CO2 control to the higher costs for all types of new generation, consumers’ rates will be taking a northward turn. Tackling climate change very well may be desirable from a public policy perspective, given the widespread impacts on the economy and our overall welfare. In terms of the cost of power, however, utilities and regulators, and others must fully understand the implications and communicate those impacts to consumers. Through education, utilities and their regulators can help consumers learn how to control their bills, in light of anticipated rate increases.
Large amounts of new capacity will be required by 2030. The cost of these capacity additions will total hundreds of billions of dollars, most of which will be absorbed by consumers. The cost of controlling and mitigating CO2 emissions will add materially to that cost, and will make a substantial difference in the type of capacity that utilities and other generators add over time.
Legislators and regulators need to be aware of the break points where one type of generation becomes more cost-effective than another. The dispatch of existing plants will not change until the cost of CO2 emissions rises above $30/ton, but above that level, coal generation falls off sharply. With regard to new plants, strong CO2 controls essentially eliminate coal plants without carbon capture. CO2 costs in the $15/ton range represent the break point for making economic decisions on the type of capacity to build. Above $20/ton, all non-coal forms of capacity (nuclear, wind and combined cycle) are cheaper than ones that use coal, while above $55/ton, IGCCs are lower in cost than combined-cycle plants.
Under all regulatory regimes, consumer bills will rise as CO2 costs are added to the mix, but those costs will differ depending on whether the market we are operating in has a competitive wholesale market or uses cost-of-service regulation. Policy design—particularly in terms of how allowances are allocated or auctioned and the level of offsets permitted—also will affect rates. The longer the delay in making the needed investments, the less flexibility utilities will have to meet the required targets from existing capacity, since they will have to make decisions very soon on what to build next in order not to compromise reliability.
There is no downside—for consumers and utilities—to knowing as soon as possible what the legislative and regulatory requirements will be with regard to carbon emissions, especially now that the Obama Administration has decided to make climate a domestic, as well as international policy priority.
1. The U.S. Census Bureau recently projected that the U.S. population will grow from approximately 304 million today to more than 430 million by 2050, a growth of about 43 percent. These new Americans will want automobiles, refrigerators, iPods and computers.
2. NERC is currently forecasting a ten-year peak growth of 1.5 percent, while the EIA’s AEO 2009 is forecasting 0.9 percent.
3. According to a recent study, China will increase CO2 emissions in 2008 by nearly 1/3 over 2007 alone, and will officially surpass the U.S. in CO2 emissions, with an economy still a fraction of the size.
4. GHG-emissions reductions of 80 percent below 2005 levels by 2050 has been called for by EEI and USCAP and a similar goal is in the Waxman-Markey Discussion Draft Legislation released earlier this year.
5. As demonstrated later in this article, every $10/ton of CO2 has the impact of raising the cost of power from coal generation on a levelized basis by about 1 cent/kWh. The average cost of power nationwide, according to EIA, was 8.9 cents/kwh at the end of 2007, while the average residential price was 10.4 cents/kWh. See http://www.eia.doe.gov/cneaf/electricity/epa/epat7p4.html.
6. A separate question is whether anything can be done that would outright lower the cost of power, as virtually every aspect of supplying electricity—capital costs, fuel costs, transmission costs, environmental costs (not just for CO2 control)— all have fluctuated substantially, and many have risen sharply. Every region and utility is different of course, but nationwide, perhaps lowering the rate of increase is the best we can expect.
7. Xcel Energy recently announced the closure of two coal plants, the development of a 200 MW solar project, and a solicitation for 850 MW of wind energy. Utilities such as PNM, PG&E, Duke and others are part of the US Climate Action Program. There are many other examples.
8. The Energy Independence and Security Act of 2007 required the improvement of lighting efficiency by approximately 1/3 by 2012, and by another 1/3 by 2020, virtually making the incandescent light obsolete. The same legislation mandated an increase in corporate average fuel economy for the first time in over 30 years (to 35 MPG), though some would argue that this was not aggressive enough. The Stimulus bill will provide billions for projects to promote renewables, biofuels and transmission that will reduce GHGs.
9. There are RPS programs in more than half the states; energy efficiency standards in about a dozen states; AB 32 in California; and increasing numbers of states that mandate net metering (retail rate payments) for renewable power generation facilities that sell their excess to the utility
10. CCS is currently expected to be able to reduce CO2 emissions by up to 90 percent.
11. Continued natural gas prices of $3-4/mmBtu would certainly change this equation, but ICF believes current natural gas prices are unsustainably low and not representative of a long-term trajectory.
12. Assumes a continuation of a cap and trade system for SO2 and NOx, albeit at tighter levels.
13. This analysis assumes the choice of plant isn’t sensitive to regulatory considerations—i.e., that it is equally challenging to site and develop each type of plant. This is clearly not the case everywhere—traditionally gas plants are easier to site than coal or nuclear—but this simplifying assumption makes sense for an overview assessment.
14. The results shown are from ICF’s Expected Case scenario, which forms the basis of the firm’s recently released Emissions and Fuel Markets Outlook.
15. ICF is currently analyzing the Waxman-Markey Discussion Draft and will be providing the results as part of the firm’s Emissions and Fuel Markets Outlook.
16. Assuming power is transacted on the spot market. Bilateral contracts could clearly differ.