2. Energy Market Impacts of a 15-Percent RPS

Electricity Sector Generation, Fuel Use, Prices, and Emissions

Figure Data

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EIA projects that the market value of renewable energy credits will remain below the 1.9 cent per kilowatthour level through 2019, when the RPS proposal requires 11.25 percent of covered sales, equivalent to 8.7 percent of total electricity sales, to be met with qualifying renewable generation (Figure 1).⁵ Although the credit price remains below 1 cent per kilowatthour through 2016, when the legislative target is 7.5 percent or below, during the period 2017 to 2019 it rises to the 1.4-to-1.9-cents-per-kilowatthour range.

Once the RPS target increases to the final 15-percent level, equivalent to 11.7 percent of total electricity sales in 2020, EIA projects continued growth in renewable generation, but with some purchase of renewable energy credits from the Federal government to satisfy program requirements. In 2020, actual qualifying generation accounts for 9.4 percent of all sales, with distributed generation credit multipliers and renewable energy credits purchased from the Federal government satisfying the rest of the 11.7-percent share requirement. By 2030, credits purchased from the Federal government account for one percent of sales out of a target equivalent to 12 percent of total electricity sales in that year. During this period, the market value of credits is 1.9 cents per kilowatthour, the price at which they can be purchased from the government.

The renewable energy credit price represents the amount per kilowatthour above the market price of power that is available to qualifying generators. The payment for renewable energy credits provides an incentive for investment in qualifying technologies even if they entail higher costs than other generating technologies. However, as the 2030 sunset date for the RPS program approaches, the period of time over which qualifying generators can anticipate receiving payments for renewable energy credits is shortened, reducing the present value of the anticipated stream of payments for renewable energy credits at any given credit price. As potential investors in qualifying projects seek to compensate for the shortening of their anticipated payment stream, there is upward pressure on credit prices. By 2020, the horizon for credit payments is short enough that investors are unwilling to invest in sufficient amounts of qualifying generation to meet the RPS target unless the credit price were to exceed the 1.9-cent price cap. As a result, electricity sellers subject to the RPS program comply through the purchase of credits from the Federal government at the 1.9 cent per kilowatthour price specified in the proposal and the level of qualified renewable generation falls short of the legislated target (Figure 2). EIA analysis of an alternative RPS requirement with no cost cap and no sunset provision indicates that the same targets as in the proposed program could be met in all years, and the credit price would generally fall below the 1.9-cent-per-kilowatthour cap.

Generation by Fuel

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Under the proposed RPS program, generation from renewable resources increases relative to the reference case (Figure 3). Biomass generation, both from dedicated biomass plants and existing coal plants co-firing with biomass fuel, grows the most by 2030, more than tripling from 102 billion kilowatthours in the reference case to 318 billion kilowatthours with the RPS policy (Table 2). Wind generation increases by almost 50 percent by 2030, from 52 billion kilowatthours in the reference case to 76 billion kilowatthours with the RPS.

Although total solar generation does not reach the level of wind or biomass, it has a higher absolute increase than wind and a higher percentage increase than either wind or biomass by 2030, when compared to the reference case. Solar generation, including utility-owned solar thermal and PV and customer-sited PV, increases from 7 billion kilowatthours in 2030 in the reference case to almost 38 billion kilowatthours with the RPS, a five-fold increase. Because customer-sited PV earns 3 credits for every kilowatthour generated, this generation counts as approximately 110 billion kilowatthours for RPS compliance purposes in 2030. This is twice the compliance share accounted for by wind and about half of the biomass compliance share. Geothermal and landfill gas facilities also show a slight increase in generation compared to the reference case.

The increase in renewable generation stimulated by the RPS primarily displaces coal fired generation. By 2030, coal generation is 3,086 billion kilowatthours with the RPS compared with 3,330 billion kilowatthours in the reference case, a reduction of about 7 percent. Coal generation is still expected to grow significantly from 2,000 billion kilowatthours in 2005. Nuclear generation is reduced by less than 5 percent, to 856 billion kilowatthours with the RPS from 896 billion kilowatthours in the reference case. As with coal, this still represents significant growth relative to 2005 generation levels. Natural gas generation is about 2 percent less than the 2030 reference case level of 932 billion kilowatthours.

Energy Prices and Expenditures

The shift away from coal to renewable fuels, together with the costs of retail electricity sellers holding RPS credits, affects electricity prices. In 2030, EIA projects the national average electricity price with the RPS to be 2 percent higher than in the reference case, i.e., 8.2 cents per kilowatthour with the RPS compared to 8.1 cents per kilowatthour in the reference case. By 2030, prices for natural gas and coal, two key fuels for the electric power sector, are lower with the RPS than in the reference case.

Cumulative costs to the electric power sector, in the form of capital expenses, maintenance costs, fuel expenditures, the purchase of RPS compliance credits from non power-sector installations, i.e., residential and commercial owners of PV systems⁶, and the purchase of credit allowances from the government are about 0.4 percent ($8.5_ billion higher with the RPS than in the reference case⁷, which total $1,963 billion in the reference case through 2030. Cumulative capital and other fixed expenditures decrease by almost $3.6 billion compared to the reference case. Offsetting this is an increase of almost $12 billion in fuel and variable costs, including net impacts of reduced fuel prices, reduced fuel usage, and new purchases of renewable energy credits from the government and end-use sectors.

With slightly higher prices, EIA projects that cumulative consumer electricity expenditures from 2005 through 2030 will increase by 0.5 percent ($21 billion) with the RPS compared to the reference case, despite slightly reduced sales. Reduced demand for natural gas results in lower natural gas prices, and cumulative end-use natural gas expenditures are reduced by 0.2 percent ($3.3 billion) of the reference case total. Net cumulative consumer expenditures for natural gas and electricity are increased by about 0.3 percent ($18 billion) through 2030 compared to the reference case.

EIA projects that residential customers will spend 0.4 percent ($7.2 billion) more for electricity with the RPS than in the reference case through 2030 and will spend 0.1 percent ($1 billion) less on natural gas, resulting in a net increase of over $6 billion. This represents just over 0.2 percent of total residential expenditures on electricity and natural gas.
Carbon Dioxide Emissions

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Although carbon dioxide emissions from the power sector increase in both the reference case and with the RPS policy, the rate of growth is lower with the policy (Figure 4). In the reference case, carbon dioxide emissions are projected to rise to 3,338 million metric tons by 2030, from approximately 2,375 million metric tons in 2005. With the RPS policy, carbon dioxide emissions are projected at almost 3,116 million metric tons in 2030, about 6.7 percent less than the reference case, but still substantially higher than in 2005. Emissions of regulated sulfur, nitrogen, and mercury emissions are not expected to significantly change with this policy because they are limited by existing programs.

Carbon Dioxide Emissions

Although carbon dioxide emissions from the power sector increase in both the reference case and with the RPS policy, the rate of growth is lower with the policy (Figure 4). In the reference case, carbon dioxide emissions are projected to rise to 3,338 million metric tons by 2030, from approximately 2,375 million metric tons in 2005. With the RPS policy, carbon dioxide emissions are projected at almost 3,116 million metric tons in 2030, about 6.7 percent less than the reference case, but still substantially higher than in 2005. Emissions of regulated sulfur, nitrogen, and mercury emissions are not expected to significantly change with this policy because they are limited by existing programs.

Comparison to Other Recent EIA Analyses of Renewable Energy Incentives

The results in this analysis are similar to earlier analyses of RPS proposals prepared by EIA. However, there are some areas where the results differ. The differences generally result from changes in the renewable sales share targeted, the price of government-issued credits that serve as a safety valve, and the fuel mix in the reference cases used for the analyses. A comparison of results from the current study of a 15-percent RPS to a 2005 analysis of a 10-percent RPS proposal, focused on results through 2025, the end-point of the 2005 analysis, shows that the small differences in results reflect changes in both the RPS proposal itself and in the baselines used for the two analyses.

In addition to the lower renewable share target, the 2005 proposal also incorporated a lower price for government- issued credits, 1.5 cents per kilowatthour versus 1.9 cents in the current proposal. The 2005 analysis, based on the reference case from the Annual Energy Outlook 2005, also started from a baseline projection that had a much larger share of natural gas generation than is now expected.

The higher renewable target for qualifying renewable generation combined with the higher cap on the price of government-issued credits, leads to a slightly larger renewable credit and generation shares in 2025 than in the 2005 analysis. The higher renewable credit price and the larger coal generation share expected in the reference case for this analysis also contribute to higher compliance costs. In the AEO 2007 reference case, natural gas was projected to be more expensive than in the AEO 2005 reference case, resulting in a less favorable market for natural gas generation and a more favorable market for coal. For wind generation in particular, which largely competes as a “fuel saver”, this resulted in less favorable market conditions, because there would be more times when the wind generation stimulated by the RPS would be displacing relatively low-cost coal instead of higher-cost natural gas. Furthermore, as new wind plants entered service in recent years, EIA has used their output data to update its assessments of new plant performance. As a result, the AEO 2007 analysis reflects somewhat lower plant capacity factors at low wind-speed sites than in the AEO2005 analysis. The combined impact of these baseline model changes is to decrease the overall contribution of wind to meeting RPS goals, and to increase the cost of compliance.

While projected cumulative electricity expenditures through 2025 fell slightly in the 2005 RPS analysis, they rise slightly in the current analysis. Projected cumulative natural gas expenditures through 2025 decline slightly in both analyses, but the reduction is larger in the 2005 analysis in which more power generation fueled by natural gas is displaced.

In another recent analysis, EIA examined the impacts of extending the production tax credit (PTC) for new wind power plants. It was found that extending the full 1.9 cent per kilowatthour PTC could have a larger impact on projected wind generation than the RPS with a 1.9 cent cap on the value of renewable energy credits considered in this report, depending on the length of the PTC extension. A 1.9 cent PTC payment per kilowatthour of generation is more valuable to qualifying renewable project developers than the sale of renewable energy credits at 1.9 cents per kilowatthour in an RPS program because the PTC is applied after taxes are calculated, and thus its value is not reduced by the tax rate.

Uncertainty

As with any long-term projections there are considerable uncertainties in these results. Among the key uncertainties are projections of the growth in the demand for electricity, future fuel prices, and the cost and performance of new generating equipment, both renewable and nonrenewable technologies. Future energy and environmental policy is also a key uncertainty.

Since coal and natural gas plants are expected to account for much of the new capacity added over the next 20 years, future coal and natural gas prices are important in determining the credit price needed to make new renewable electricity competitive with other generation options. If coal and natural gas prices turn out to be lower than are projected in this report, the renewable energy credit price needed to make renewables competitive would be larger. Conversely, it would be lower if coal and natural gas prices turn out to be higher than expected.

Projections of the future cost and performance of new generating equipment are always difficult, particularly for technologies that currently have little or no market experience. Nonhydroelectric renewable technologies currently produce about 2 percent of the power generated in the United States. Spurring the market penetration of these technologies with an RPS might allow developers to make reductions in their costs and improve their performance through mass production techniques and learning by doing. These types of improvements are assumed to occur and are incorporated in the NEMS.

For wind, solar, and biomass technologies, the level of development called for with the proposed RPS comes with some uncertainty. For example, developers or grid operators may have to pay to build or upgrade long transmission lines from the remote areas with ample wind resources to the cities with significant demand. In this analysis, costs are assumed to increase as developers turn to more costly sites such as those with higher interconnection costs, higher land costs, or more difficult terrain. However, there is significant uncertainty about the actual cost increases that might occur, and these actual costs may be more or less than projected.

Wind and solar power development may also be constrained by its intermittent nature which leads to the need for backup capacity to ensure that consumers’ need for electricity can be met at all times. At regional penetration levels seen for wind in this analysis, NEMS represents many of the most significant costs of accommodating wind intermittency, including costs for additional firm system capacity, potential mismatch between load and wind-production peaks, and lost revenue during periods of excess wind production.

The solar resource development seen in this report would largely occur at the customer site, on the distribution rather than on the transmission system. Such a level of penetration may have minor or significant effects on system cost and reliability, largely depending on localized concentration of installations and the pre-existing condition of local distribution systems.

As with wind, data suggest that there are sufficient biomass resources to fuel the increased biomass generation projected in the RPS case. However, currently there are very few coal plants that co-fire with biomass. To achieve the level of biomass co-firing called for in the RPS case, the infrastructure to reliably gather, process, and deliver the available biomass to coal plants would have to be developed.

Finally, EIA assumes the use of biomass gasification technology for dedicated biomass generation plants. Based on current estimates, these plants trade off somewhat higher capital costs for significantly improved efficiency compared to direct-combustion technology, thus reducing operating costs. However, few commercial biomass gasification operations currently exist, and capital costs for this technology are highly uncertain.

As previously noted, almost half the States have adopted an RPS or similar renewable energy target policy. In addition, a number of States, particularly in the Northeast and Western United States, have taken initial steps to regulate carbon dioxide emissions. At the Federal level, key renewable energy subsidies are scheduled to expire within the next 2 years, and there are a number of proposals in Congress to establish national carbon dioxide emission legislation. The implementation of any combination of these policies would be expected to have a significant impact on renewable generation markets and could significantly affect the cost of achieving the proposed RPS policy or the allocation of the compliance cost among affected parties.

Interaction with State RPS policy is discussed earlier in this report. If renewable generation is seen as a cost-effective means of reducing carbon dioxide emissions, the cost of new renewable generation might be allocated between the RPS credit price and the cost of achieving the carbon dioxide regulation, reducing the apparent standalone cost of one or both programs, but not reducing total costs. If the renewable generation targets in this proposal exceed the cost-effective renewable mix of future carbon dioxide regulations, then this proposal might increase the cost of carbon dioxide reductions relative to a standalone carbon dioxide policy, while at the same time transferring some of the cost from the carbon dioxide program to the RPS program. The extension of direct or indirect government subsidies for renewable energy, such as the PTC for wind, biomass, and geothermal or the ITC for solar, would likely reduce the apparent cost of RPS compliance by transferring a significant component of that cost to government budgets rather than electricity producers and consumers.

Notes