Introduction

This report responds to requests from Chairman Edward Markey, for an analysis of a 25-percent Federal renewable electricity standard (RES).  The RES proposal analyzed in this report is included in the discussion draft of broader legislation, the American Clean Energy and Security Act (ACESA) of 2009, issued on the Energy and Commerce Committee website at the end of March 2009.³  The two request letters and the relevant section of the ACESA discussion draft are provided as Appendices A, B, and C of this report.  

While Chairman Markey’s original letter asked that sensitivities with alternative greenhouse gas policies be prepared, his subsequent letter released the Energy Information Administration (EIA) from that requirement.  Consequently, the analysis presented here does not consider the interactions of the RES provisions contained in ACESA with other key provisions of that legislation. An analysis of these interactions will not be possible until some open issues in the ACESA discussion draft are resolved.  However, this report does provide a qualitative discussion of potential interactions with an energy efficiency resource standard (EERS) and a cap-and-trade program for greenhouse gases, two other programs that are also included in the ACESA discussion draft.

Background

An RES, also known as a renewable portfolio standard (RPS), is a policy that requires covered electricity retailers to supply a specified share of their electricity sales from qualifying renewable energy resources.  As of the end of 2008, 28 States and the District of Columbia had enacted an RPS or similar renewable energy requirement. The Federal RES analyzed here would apply to electricity retailers on a nationwide basis, establishing a target level for the market share of qualifying renewable resources that grows from 6 percent in 2012 to 25 percent in 2025 and beyond.

To stimulate an increase in the use of renewable resources to generate electricity, an RES requires that a specified share of the power sold must be produced from qualifying renewable facilities. Companies that generate power from qualifying renewable facilities are issued credits that they can hold for their own use or sell to others. To meet the RES requirement, each covered electricity seller must generate their own qualifying renewable power or purchase renewable energy credits from others.  For example, a covered electricity retailer with 100 billion kilowatthours of retail electricity sales in a year with a 25-percent RES requirement would have to generate or purchase credits representing a combined total of 25 billion kilowatthours of qualifying renewable power for that year. In a competitive market, the price of renewable energy credits should rise to the level needed to stimulate powerplant developers to construct the amount of qualifying renewable capacity needed to meet the RES requirement while allowing the market to determine the most economical renewable compliance options to develop.

The RES program analyzed in this report has the following characteristics:

• The program begins in 2012 with the required renewable share starting at 6 percent and growing in scheduled increments to 25 percent in 2025. The program sunsets in 2040.

• Power sellers with retail sales of at least 1 billion kilowatthours (1,000,000 megawatthours) are covered. Entities with retail sales below this level are exempt.

• Generation from existing hydroelectric and municipal solid waste (MSW) facilities are not included in the base electricity sales but also do not earn compliance credits.

• The total amount of qualifying renewable generation required each year is calculated by multiplying the base (total electricity retail sales minus existing hydroelectric and MSW generation and sales by exempt small retailers) by the required share.

• Qualifying renewable facilities include all new and existing nonhydroelectric renewable generation facilities, including co-firing modifications to existing coal plants⁴ that are placed in service on or after the enactment date of the legislation. Qualifying fuels include incremental hydropower⁵, geothermal, solar, wind, ocean, landfill gas, and certain biomass feedstocks.

• Generation from distributed renewable generation resources, i.e., customer-sited facilities such as roof-top photovoltaics and small wind turbines, earns three credits for every kilowatthour of generation through 2014, with a discretionary adjustment possible after 2014.⁶For purposes of this analysis, it is assumed that the credit will be reduced to one credit per kilowatthour after 2014, because the affected distributed generation resources show significant growth prior to 2014 when they receive triple credits and continue to grow slowly after 2014, indicating that have approached competitiveness in some markets.

• Credits are granted for qualified State energy efficiency programs to satisfy up to 20 percent of the RES requirement upon petition of the governor of any State provided that the State is in compliance with the EERS provisions of the bill.

• The market value of credits used for compliance is capped at 5 cents per kilowatthour, adjusted annually for inflation. Power sellers may purchase an unlimited number of alternative compliance credits from the Federal government at this “safety-valve” credit value, allowing them to meet their program obligations without providing additional renewable generation.  Revenue from the sale of government-issued credits will be returned to retail suppliers in proportion to the credits they submit.

• The program does not affect any State-level RES requirements or similar obligations.

Analysis Cases

The analysis presented in this report starts from an updated version of the Annual Energy Outlook 2009 (AEO2009) reference case that reflects the projected impacts of the American Recovery and Reinvestment Act (ARRA), enacted in February 2009, and revised economic assumptions.  ARRA has a significant impact on the projected growth of renewable energy over the next 5 years, so it is important to take account of its enactment in considering the projected impacts of an RES requirement.  For example, overall targets for renewable generation in this RES proposal, on a credits-earned basis, are below projected renewable generation in the updated reference case through 2015.

The development of the updated reference case is described in a recent EIA report An Updated Annual Energy Outlook 2009 Reference Case Reflecting Provisions of the American Recovery and Reinvestment Act and Recent Changes in the Economic Outlook.⁷  As noted in that report, EIA plans to use this updated baseline in its analyses of proposed changes in laws and regulations, including the RES analysis presented in this report.  Therefore, the term “reference case” in this report means this updated reference case unless otherwise stated.  

The RES proposal that is the subject of this report contains a provision requiring the Secretary of Energy to adjust the credit multiplier for distributed renewable generation to maintain it at a level “no higher than the Secretary determines is necessary to make distributed generation facilities cost competitive with other sources of renewable electricity generation.”  Enforcement of this provision will require significant discretion from the Secretary, which EIA is unable to analyze.  Based on the market response of distributed renewable resources in the reference case, EIA has assumed that distributed renewable resources will be assigned a multiplier of one beyond 2014, the earliest date for adjustment of the initial multiplier of three in the two RES policy cases analyzed in this report.

One key difference between the RES proposal contained in H.R. 890 and the RES in the ACESA discussion draft that is the focus of this report is that the latter provides for the inclusion of credits for qualified State energy efficiency programs to satisfy up to 20 percent of the RES requirement upon petition of the governor of any State provided that the State is in compliance with the EERS provisions of the bill.  As the baselines for and details of the yet-to-be-established EERS program are unknown, the extent to which States would have access to efficiency credits for purposes of the RES is not clear.  In order to assess how different outcomes regarding the application of efficiency credits might affect the projected impacts of the RES, EIA analyzed two RES policy cases.  The RES with Full Efficiency Credits (RESFEC) case assumes that the maximum level of efficiency credits, up to one-fifth of the credits in the target in any given year, are claimed.  This is reflected as a 20-percent reduction in the applicable target for eligible renewable generation.  The RES with No Efficiency Credits (RESNEC) case assumes that States cannot qualify for, or elect not to use, efficiency credits, so that the RES targets stated in the proposal are used as the actual targets for eligible renewable generation.  

This report provides an analysis of the RES provisions in the ACESA discussion draft on a standalone basis.  The impact of the EERS on the overall growth in electricity load, which could also affect the projected effects of an RES, is also not clear.  A cap-and trade program for greenhouse gas emissions could also affect RES impacts.  These interactions are beyond the scope of the analysis in this report, but they are addressed qualitatively.

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Results

Required Level of Renewables

The level of renewables required to comply with the RES will be lower than the nominal target because of the exemptions and baseline adjustments.  Figure 1 illustrates the derivation of the overall share of renewables required when these factors are taken into account.  While the nominal share in 2025 is 25 percent, exempting the small retailers lowers the effective target to 22 percent of total electricity sales.  The effective target is lowered further to 21 percent when the generation from hydroelectric power and municipal solid waste is removed from the sales baseline.  The effective target will be lowered still further by the degree to which qualifying energy efficiency credits are used.  If States are able to take full advantage of the energy efficiency credits, using them to meet up to 20 percent of the RES requirement, the effective share of renewables required could drop to approximately 17 percent of total electricity sales.  These values are both greater than the 11-percent share of total electricity sales achieved by eligible renewables in 2025 in the reference case in this report.

Electricity Sector Results

Under both the RES simulations prepared, generation from renewable resources increases relative to the reference case (Figure 2).  However, the growth in renewable generation, particularly for wind, stimulated by State RES programs and ARRA in the reference case plays a major role in compliance with the Federal RES.  For example, in the reference case, wind generation increases from 32 billion kilowatthours in 2007 to 208 billion kilowatthours in 2030.  This increase in wind generation accounts for a significant share of the increase in renewable generation require with the Federal RES.  In the cases analyzed in this report, biomass generation, both from dedicated biomass plants and existing coal plants co-firing with biomass fuel, also plays a major role in compliance with the Federal RES, with biomass generation more than doubling from 218 billion kilowatthours in the reference case to 438 billion kilowatthours in the RESFEC case and 577 billion kilowatthours in the RESNEC case (Table 1).  Unlike for wind, the renewable provisions of ARRA did not have as large an impact on biomass because the co-firing of biomass only receives half the credit available to new wind plants and new dedicated biomass plants generally take longer to develop than the period of the credit extension in ARRA.

Wind generation in the RESFEC case reaches the same level (208 billion kilowatthours) as in the reference case by 2030, but in the RESNEC case wind generation increases to 249 billion kilowatthours.  Although total solar generation does not reach the level of wind, it has a higher percentage increase than wind by 2030, when compared to the reference case.  Solar generation, including utility-owned solar thermal and photovoltaics and customer-sited distributed generation, increases from 23 billion kilowatthours in 2030 in the reference case to 30 billion kilowatthours in the RESFEC and 31 billion kilowatthours in the RESNEC case, an increase of 30 percent and 35 percent, respectively. 

The increase in renewable generation stimulated by the Federal RES leads to lower projected coal and natural gas generation.  In the two RES cases, coal generation ranges between 182 billion kilowatthours (8 percent) and 257 billion kilowatthours (11 percent) below the reference case level.  Similarly, natural gas generation in the two RES cases in 2030 is between 55 billion kilowatthours (6 percent) and 150 billion kilowatthours (15 percent) below the level projected in the reference case.

Given the amount of eligible renewable generation projected in the reference case, the RES is not expected to affect national average electricity prices until after 2020.  As the required RES share increases to its maximum value in 2025, the value of RES credits increases and impacts on national average electricity prices become evident.  The peak effect on national average electricity prices, 2.7 percent in the RESFEC case and 2.9 percent in the RESNEC case, occurs as the required renewable share ramps up more rapidly than the demand for electricity is growing.  In the later years of the projections, the impact on national average electricity prices is smaller, as the impact of the RES requirement on the cost of coal and natural gas, fuels whose use is reduced by added renewables, is increasingly reflected in electricity prices.  By 2030, electricity prices are projected to be little changed from the reference case in both RES cases, with 2030 prices less than 1 percent higher than in the reference case.

By 2030, natural gas prices, measured as the average wellhead price, have decreased 1 percent in the RESFEC case and 4 percent in the RESNEC case, relative to the reference case. Also by 2030, average minemouth coal prices relative to the reference case have decreased 2 percent in the RESFEC case and 4 percent in the RESNEC case.

Renewable credit prices do not rise above zero in either RES proposal until 2020. The RESNEC case generally results in a higher credit price than the RESFEC case.  In both cases, credit prices reach a maximum of 5 cents per kilowatthour in 2024 and maintain this price through 2028, after which time the price begins to drop as electricity demand grows enough to absorb the required growth in renewables.  In 2030, the RESFEC case results in a credit price of 2.5 cents per kilowatthour and the RESNEC case results in a credit price of 3.5 cents per kilowatthour. 

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Regional Results

Compliance with RES targets can vary significantly by region.  Although all regions do provide some significant fraction of their required renewable generation from in-region sales, some tend to over-comply and thus are able to sell credits to other regions, and other regions tend to under-comply and need to purchase credits to achieve compliance.  Several factors contribute to a region’s overall tendency to be a net credit importer or exporter, including:

• Cost and availability of renewable resources.  Regions with low-cost and/or abundant resources may be able to comply more economically or to a greater extent than other regions.  Some regions may also be able to access lower cost resources in an adjacent region, with additional investment in transmission improvements.
• Cost of alternative generation options.  Regions that rely on more expensive conventional generation options, such as natural gas, will see reduced compliance costs, even with relatively expensive or limited renewable resources, as credit prices are a function of the spread between the cost of the renewable and the cost of the displaced generation.
• State incentives for renewable generation.  Some regions may have State RES requirements in excess of the net Federal requirement for that region and, as a result, will necessarily over-comply with the Federal RES.

Because of regional differences in electricity market structure, State RES requirements, and ability to utilize resources, regional compliance surpluses or deficits may have differing price impacts, as shown in Figures 3 through 5.  In regions dominated by traditional cost-of-service regulation, the net cost increases or decreases from RES compliance are generally passed through to consumers; in regions with more open electricity market structures, these changes in costs will only be passed through to consumers to the extent that market forces allow and will otherwise by absorbed by the industry.  In cases where one region may be building dedicated renewable energy resources in an adjacent region, costs and benefits may be shared between the two regions, as the host region will realize the local economic benefits such as employment and land-owner payments, but also local costs such as any undesirable land uses, and the ownership region will receive any net proceeds from the operation and sale of credits, however, price impacts will tend to be in the ownership region.

By 2020, when the RES targets first start to result in significant new capacity builds above reference case levels, most regions start to see an increase in electricity prices, with most regions seeing an increase of 2 to 5 percent above reference case levels through 2025.  After 2025, prices begin to return to reference case levels, and by 2030 they are generally 1 percent to 3 percent higher than projected in the reference case.  In a few regions, especially the MAPP region (covering the northern Great Plains States), with abundant and low-cost renewable resources, prices fall below the reference case level.  In the RESNEC case, ERCOT (covering most of Texas) also sees a significant decrease in electricity prices compared to the reference case, as a result of the significant wind resources of Texas and also because of the significant reliance of that region on natural gas as a generation fuel.  The RES leads to lower natural gas use and prices, which benefits regions that rely heavily on natural gas.

Carbon Dioxide Emissions

This analysis is of the RES portion of the ACESA discussion draft and does not account for the various carbon-reduction policies that affect other markets outside of the electric power sector.  Within the electric power sector, the RES is projected to result in reductions in carbon dioxide emissions relative to the reference case (Figure 6).  In the RESFEC and RESNEC case, electricity sector carbon dioxide emissions in 2030 are projected to be 2,444 million metric tons and 2,333 million metric tons  respectively, compared to 2,639 million tons in the reference case and 2,433 million tons estimated in 2007.

Interactions Between the RES, the EERS, and the Cap-and-Trade Program for Greenhouse Gas Emissions in the ACESA Discussion Draft

EIA’s modeling of the RES in the ACESA discussion draft was a standalone analysis that did not consider interactions with other key programs in the ACESA discussion draft.  While EIA cannot develop an integrated analysis until there are clearer insights into how some of the other ACESA programs would actually be implemented, interactions among the elements of ACESA could be significant.

In previous analyses of economy-wide policies to limit or reduce emissions of greenhouse gases, EIA has generally found that a cap-and-trade program for greenhouse gases leads to significant growth in the use of renewable energy for electricity generation, which becomes more attractive when the cost of using fossil fuels goes up.     Where there are multiple targets that can be satisfied with the same energy resources and projects, the target that sets the upper limit on the use of the resource will generally absorb all of the incremental costs from that resource, making compliance with the non-binding goal appear to be costless.  To the extent that the proposed cap and trade program induces more renewable resources than required by the concurrent RES proposal, one might expect a reduction in apparent RES compliance costs, since those costs would already be reflected in the value of carbon dioxide allowances.

In contrast, an EERS, which reduces or eliminates projected growth in electricity load, and therefore the need for additional generation capacity, makes it more likely that a given RES target will require that generation from new eligible renewable capacity replace generation from existing capacity rather than from other types of new capacity.   The cost penalty associated with backing out existing capacity, whose capital cost is already sunk, is typically much larger than the cost penalty associated with backing out alternative types of new capacity.  The EERS in the ACESA discussion draft calls for a 15-percent reduction in load relative to the EERS baseline between 2012 and 2020, with further reductions beyond 2020 to be established through a rulemaking process.  Although the relationship between the EERS baseline and the updated AEO2009 reference case is far from clear, projected electricity demand growth in the updated AEO2009 reference case, before application of an EERS, is only about 1.0 percent per year from 2008 through 2030.  If the EERS program in fact leads to a significant reduction in projected demand growth relative to the updated AEO2009 baseline, many regions would likely have little if any need for new capacity, so new generation from eligible renewables required to meet the RES target would be backing out generation from existing capacity. 

Uncertainties

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.

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 3 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 National Energy Modeling System (NEMS), EIA’s long-term domestic energy model.

However, it could turn out that the current relatively low market shares for these technologies result from high costs that cannot be easily reduced. In addition, even if renewable technology developers are successful in improving the cost and performance of their technologies, their ability to penetrate the market will depend on the relative costs and performance of nonrenewable technologies. If renewable and nonrenewable technologies improve by similar amounts, the relative advantage that nonrenewable technologies have today would likely remain. If renewable technology improves at a faster rate than assumed, compliance costs could be less than projected.

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 the actual costs may be more or less than projected.

Wind and solar power development may also be constrained by the intermittent nature of the resource which may lead to the need for additional 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 when needed, 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 relatively 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.  Utilities with coal plants may also be resistant to investing in them to allow them to use biomass, if they believe that future climate policy may lead them to shut the plant down or reduce its utilization.

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.

Notes