Emission Reduction Policies and Implicit Carbon Prices in the United States
Resources for the Future
April 20, 2011
This report contains the work performed for the Australian Productivity Commission’s study on emission reduction policies and implicit carbon prices in key economies. The report describes key electricity and transportation policies at the federal, state, and local levels in the U.S. For many of the policies, estimates of abatement and implicit carbon prices are also provided.
The next section presents a background to the electricity sector and transportation sector in the U.S. and describes the methodology used to estimate abatement and implicit carbon prices. Section 2 covers electricity policies and section 3 covers transportation policies. Section 4 concludes with two table that summarize the key data for the policies.
1 Background and methodology
The electric power sector in the United States is quite complex in terms of regulatory institutions, markets and technologies. This discussion highlights the aspects of the sector that pertain most directly to the policies discussed in the next section. In particular, I focus on generation markets in which owners of electricity generators supply electricity to retailers and large industrial consumers. There is a brief
discussion of transmission at the end of the section, and I do not discuss retail markets or the distribution system in any detail.
1.1.1 Existing and forecasted generation stock
) emissions by major technology for 2009. Table 1 shows the share of generation and carbon dioxide (CO2
For reference, total generation is about 4 billion megawatt hours (MWh). The table shows that coal accounts for about half of total generation and almost four-fifths of emissions. Wind accounted for about 2 percent of generation and biomass about 1 percent. The “other” category includes wind,
biomass, oil, and a number of minor technologies.
Many of the generators are quite old, particularly the coal generators. Figure 1 shows the generation capacity of coal generators in operation in 2009 for 5-year age bins. About 70 percent of the coal generation capacity is between 20 and 45 years old. Absent unexpected policy or energy market changes, most of these units are predicted to continue operating for a long time. The Energy Information Administration (EIA) forecasts that only about 5 GW of coal generation capacity will be retired by 2035 (EIA 2010). Over the same time period, about 200 GW of new investment is expected to be needed to meet new demand, of which about 30 percent would be wind, 13 percent coal, and most of the remainder natural gas. Because coal has much higher emissions than the other technologies, the CO 2
emission intensity (emissions per MWh of generation) is expected to decrease slightly.
1.1.2 Structure of markets for electricity generation
It is useful to distinguish wholesale electricity markets, in which generators supply electricity to retailers and industrial customers, from retail markets, in which retailers sell electricity they have purchased on the wholesale market to households and businesses. This section focuses on wholesale markets. Wholesale market structure varies widely across the country. Some regions, such as the Northeast, Mid-Atlantic, Texas, and California, have active wholesale markets. In these markets, typically some amount
of electricity is provided as part of long term contracts, and a short-term (e.g., day-ahead) market matches the remaining demand and supply at hourly or sub-hourly intervals. There may also be balancing markets that operate at shorter time scales to account for unexpected fluctuations in demand or supply.
Often these markets are structured so that owners of generators bid to supply electricity at a particular price. Offers are stacked in order of increasing bids, and the equilibrium price is equal to the highest bid such that total supply equals expected demand. In a competitive market, firms submit bids equal to their marginal cost, and the equilibrium price equals the marginal cost of the highest-cost generation unit needed to meet demand.
emissions perspective, it is important that the highest-cost generation unit changes over From a CO2
time. Throughout the analysis, costs refer to marginal costs. As indicated by the Commission, the analysis focuses on the short run, in which capital costs are sunk. When demand is low, only a small set of the available units in the system operate—i.e., the lowest-cost generators. During such times, the
marginal cost of the highest-cost unit in operation is low, and the electricity price is correspondingly low. As demand increases, increasingly high-cost units turn on, and the price increases. In other words, the supply curve can be constructed by ranking units in order of increasing marginal costs. As the demand curve shifts out, higher-cost generators must be used, and the electricity price increases. This discussion disregards operational constraints that many units have, such as limits to the amount that generation can vary from one time period to the next. Nevertheless, it is a useful approximation for the policy analysis below.
The preceding discussion has assumed that there is sufficient capacity to meet demand. When demand is very high, or many units are unavailable, all generators in the system may be operating. In that case, the price could exceed the marginal cost of the highest-cost unit.
This raises the possibility that firms may withhold supply to manipulate the price. There has been a long debate over the extent to which wholesale markets are perfectly competitive, particularly following the extremely high electricity prices and rolling blackouts in California in 2000 and 2001. Many analysts believe that whatever the situation during that period, wholesale markets are fairly competitive and are certainly more competitive now than they were ten years ago. For the purposes of this report, I assume that wholesale markets are perfectly competitive, so that firms do not strategically withhold supply and submit bids equal to their marginal cost.
In an effort to protect consumers from imperfect competition and more generally from having to pay high electricity prices, many markets impose price caps. Although price caps do prevent very high prices from occurring, such caps lead to insufficient investment in new generation capacity. Installing a new generator of any size or fuel type requires an up-front capital investment. This investment can be recovered over the lifetime of the generator during times when the price of electricity exceeds the marginal cost of that generation unit. Therefore, setting a price cap tends to depress investment because it lowers prices and reduces the ability to recover the initial investment cost. To address this problem, many regions of the U.S. have introduced capacity markets, in which units receive payments from the retailer for having generation capacity available. The goal of these markets is to provide enough incentive for investment in new generation capacity—if there is insufficient capacity available,
prices will be high in the capacity market, which spurs entry.
By comparison, many regions of the country operate under traditional cost-of-service regulation. The canonical model is that a vertically integrated utility makes generation and transmission investment decisions subject to the approval of the state regulator, whose objective is to minimize the cost of meeting electricity demand. Generators are dispatched to meet demand in order of increasing cost, similarly to a wholesale market.
The distinction between cost-of-service and wholesale market competition is not as sharp as this discussion would suggest, however. For example, regulated utilities may be able to sell excess electricity into wholesale markets. Below, the policy analysis will reflect the actual market and regulatory conditions as closely as possible.
1.1.3 Marginal emission rate
Many of the policies discussed below create incentives for firms to invest in generation capacity of low-emission technologies such as wind, solar and biomass. This investment displaces generation from existing units in the short run, and displaces investment and generation in the long run. Abatement,
emissions caused by the policy, depends on emissions from the defined as the decrease in CO2
generation that is displaced in the short run and long run. This paper focuses on the short run, in which the rest of the generation system is fixed. As discussed next, the marginal emission rate is a useful concept.
Consider, first, an incremental change in a policy that causes a small amount of investment in a low-emission technology. The displaced emissions at any point in time are equal to the emission rate of the generation unit that is displaced—or, as discussed above, the emission rate of the highest-cost unit that would have been operating at that time. I refer to this emission rate as the marginal emission rate. When demand is low, the marginal emission rate is equal to that of a relatively low-cost generation unit, but when demand is high, the marginal emission rate is equal to that of a high-cost generation unit. For example, if a power system relies mostly on natural gas, the marginal emission rate increases with demand as higher-cost, and higher-emitting, natural gas units are used at the margin. For an incremental policy change, the displaced emissions depend on the marginal emission rate. This emission rate varies substantially across power systems. Table 2 reports the share of generation by fuel type for some of the largest power systems in the U.S. for 2008. The bottom row reports the U.S.
average, which is similar to the 2009 estimates from Table 1. The other rows report generation shares for different power systems, and they show a tremendous amount of variation. For example, the Midwest relies mostly on coal, whereas New England uses very little coal. These differences suggest that the emission rate of the marginal unit varies across regions. Note that they are merely suggestive—for
the policy analysis what matters are the marginal emission rates and not the average emission rates—
but the table does demonstrate the need to be careful about estimating abatement for different regions. In summary, abatement for an incremental policy can be estimated as long as the emission rate of the marginal unit is known at every point in time. For some regions, such as California, this is relatively straightforward, as natural gas is the marginal technology most of the time. For other regions like Texas, natural gas is sometimes marginal but coal may be marginal at night when demand is low (Castillo and Linn, 2011). These differences will be recognized in the abatement and carbon price estimates in the following section.
Estimating abatement for policies that cause more than an incremental amount of investment is far more challenging because the marginal generation unit is affected by the policy. In these cases, a model of the power system is usually needed to account for this effect.
Transmission plays an important role in the way these policies function. Because transmission investment is not centrally planned in the U.S. and there are many regulatory and economic obstacles to constructing a new transmission line, it is often extremely challenging to coordinate transmission investment with electricity policies. For example, federal and state policies have caused a dramatic amount of wind investment in Texas. Most of the installed wind systems are in west Texas, but most of electricity demand is further east, and there has not been enough transmission capacity to allow the wind generated in west Texas to meet demand in the east. As a result, much of the wind generation had
to be curtailed, and abatement was much less than it would have been in the absence of transmission constraints.
When possible, transmission constraints are accounted for when estimating abatement. The estimates should therefore be interpreted as the effect of the policies conditional on transmission policies and investments.
Most of the transportation policies affect either the new vehicles market or the markets for transportation fuels. This section provides a brief overview of both markets.
1.2.1 The market for new passenger vehicles
Total sales in the new vehicle market were around 15 million in the mid 2000s, but sales have been 10-12 million in the past several years. The market is fairly concentrated, and the top 8 firms accounted for 88 percent of the market in 2008. GM, Toyota and Ford were the top three manufacturers that year. About half of the vehicles sold are passenger cars. The remainder is light trucks, which include sport utility vehicles, crossover vehicles, minivans and pickup trucks.
The corporate average fuel economy (CAFE) program is the major policy aimed at improving the fuel economy for new vehicles. The program applies separate standards for cars and light trucks that each automaker must meet. Figure 2 shows the standard for cars as well as the average fuel economy of cars in the U.S. market from 1975-2007. Average fuel economy has exceeded the standard nearly every year, but this figure masks the effects of the standard. The three U.S.-based automakers, Chrysler, Ford and GM, have generally met the standard. In contrast, Honda, Toyota and some other Asian automakers have exceeded the standard by a wide margin, whereas some European firms have failed to meet the standard and instead paid a fine for non-compliance. Research has concluded that standards have been binding for U.S. automakers but not for automakers that regularly exceed the standard (Jacobsen, 2010).
This heterogeneity has important implications for understanding the effect on the new vehicle market of an increase in the standard. A modest increase in the standard, say 1 mpg, could lead to an increase in average fuel economy that is less than 1 mpg. Constrained firms increase fuel economy, but some firms that exceed the standard may actually reduce their vehicles’ fuel economy (Klier and Linn, 2010). This consideration may be less important for a very large increase in the standard, in which case the standard would be binding for all firms in the market, but it should be considered when estimating abatement as the standard is phased in.
1.2.2 Fuel markets
emissions by promoting renewable A large share of the transportation policies attempt to reduce CO2
fuels such as ethanol and biodiesel. Consequently, the discussion of fuels markets focuses on the supply and demand for these fuels. The EPA rulemaking for the renewable fuel standard (EPA, 2010) provides an extensive background to these industries, and is the primary source for the following discussion. Ethanol consumption in 2010 was about 12.5 billion gallons, and biodiesel was roughly 500 million gallons. Most of the ethanol and biodiesel were produce domestically; a small, although growing amount of ethanol has been imported from Brazil where it is refined from sugar. Most of the ethanol was produced from corn starch and most of the biodiesel from soy. Although the corn starch technology is fairly mature, there is a vast amount of research at universities, government laboratories and private firms into alternative feed stocks and processing technologies. Some demonstration-stage plants produce cellulosic ethanol and biodiesel, but nothing yet is at commercial scale. Although cellulosic and certain biodiesel fuels are closest to marketability of the alternative technologies, there is a vast array of other possibilities currently under investigation.
Corn grown for ethanol is concentrated in Iowa, Illinois, Nebraska, Minnesota and South Dakota, which collectively account for two-thirds of total production. In 2008, 30 percent of the corn grown in the U.S.
was used to produce ethanol. This large share, and the prospect of greater ethanol production in the future, has raised concerns about the effect of ethanol production on corn prices. Roberts and Schlenker (2010) suggest that this effect could be quite large, but this discussion is beyond the scope of this report. After the corn is collected it must be refined into ethanol. The top 9 firms account for about 45 percent of capacity. Based on this fairly low concentration, it seems reasonable to assume that this market is competitive.
Demand for ethanol comes from several sources. First, ethanol is a gasoline substitute. If the price of gasoline is sufficiently high compared to the price of ethanol, fuel blenders will choose ethanol instead of gasoline. Second, in some regions ethanol is used to meet fuel standards or environmental regulation. This is an important consideration when analyzing the effect of a national quantity-based standard on ethanol production; in the absence of the standard ethanol production would still be substantial even if ethanol prices are high.
Finally, ethanol may be consumed as E85, which is 85 percent ethanol and 15 percent gasoline. As opposed to lower ratios of ethanol such as E3 or E10 (3 or 10 percent ethanol), which are certified for use by all passenger vehicles, E85 can only be used by vehicles that have certain equipment. Many manufacturers sell vehicles that have this capability, and existing vehicles can be retrofit at a cost of several hundred dollars. Nonetheless, because of the specialized vehicle equipment, there is a fixed cost of using E85. There is also a fixed cost to providing E85 at retail gasoline facilities. Also, special dispensers and storage equipment are needed for E85; the EPA estimates that the cost of installing a dispenser at a gasoline station is $140,000-170,000. Currently, there are about 160,000 retail gasoline facilities in the U.S., about 1,200 of which can dispense E85.
The specialized vehicle, dispensing and storage equipment introduce a challenge to reaching higher levels of E85 consumption. If few retail facilities have E85, few consumers will purchase flex-fuel vehicles
or retrofit their existing vehicles, in which case there is little incentive for retail facilities to offer E85. Corts (2010) shows that government fleet adoption can solve this chicken-or-egg problem by requiring government vehicles to use E85. This prompts retail gasoline facilities to offer E85, which increases the number of consumers who drive a vehicle capable of using E85.
Conditional on owning a vehicle capable of using E85 and on fuel availability, whether consumers purchase E85 depends on the relative price of gasoline and ethanol, of course. Fuel economy is about 30 percent lower with E85 than with gasoline, so E85 should sell at a discount. In general, E85 is not sufficiently discounted to account for the sacrificed fuel economy (Anderson, 2010). Consequently, consumers who purchase E85 are not aware of the fuel economy issue, or they have strong environmental or other reasons for purchasing E85.
Beyond these issues, there are infrastructure and regulatory challenges to increasing the use of biofuels. First, before it can be sold for retail, ethanol must be blended with gasoline and biodiesel with diesel fuel. Because existing refineries are located in middle of country, and fuel blenders tend to locate on the coasts, the biofuels must be transported considerable distances. Currently, this is done mostly by rail, barge and truck. Ethanol is more costly to transport than biodiesel because it is difficult to use pipelines. Furthermore, special storage and dispensing equipment is needed for ethanol.
A second challenge to reaching higher levels of ethanol consumption is the “blend wall”. Currently, ethanol distribution and blending infrastructure, industry standards, and regulations allow for ethanol blends up to 10 percent ethanol (E10); it is not practical to produce blends higher than E10 other than E85. Therefore, with national demand for gasoline around 140-150 billion gallons per year, if all of the gasoline were E10, this would translate to 14-15 billion gallons of ethanol per year. To produce and consume more than this would require greater use of E85—which is challenging for reasons discussed
above—or changes in the regulation and industry standards.