Analysis Methodology

The projections and quantitative analysis for this paper were prepared using the Electricity Market Module (EMM) of the National Energy Modeling System (NEMS). NEMS is a computer-based, energy-economic model of the U.S. energy system for the mid-term forecast horizon, through 2025. NEMS projects production, imports, conversion, consumption, and prices of energy, subject to assumptions about macroeconomic and financial factors, world energy markets, resource availability and costs, behavioral and technological choice criteria, cost and performance characteristics of energy technologies, and demographics. Using econometric, heuristic, and linear programming techniques, NEMS consists of 13 submodules that represent the demand (residential, commercial, industrial, and transportation sectors), supply (coal, renewables, oil and natural gas supply, natural gas transmission and distribution, and international oil), and conversion (refinery and electricity sectors) of energy, together with a macroeconomic module that links energy prices to economic activity. An integrating module controls the flow of information among the submodules, from which it receives the supply, price, and quantity demanded for each fuel until convergence is achieved.

Domestic energy markets are modeled by representing the economic decisionmaking involved in the production, conversion, and consumption of energy products. For most sectors, NEMS includes explicit representation of energy technologies and their characteristics. In each sector of NEMS, economic agents—for example, representative households in the residential demand sector and producers in the industrial sector— are assumed to evaluate the cost and performance of various energy-consuming technologies when making their investment and utilization decisions. The costs of making capital and operating changes to comply with laws and regulations governing power plant and other emissions are included in the decisionmaking process.

The EMM simulates the capacity planning and retirement, operating, and pricing decisions that occur in U.S. electricity markets. It operates at a 13-region level based on the North American Electric Reliability Council (NERC) regions and subregions. Based on the cost and performance of 27 different generating technologies, the costs of fuels, and constraints on emissions, the EMM chooses the most economical approach for meeting consumer demand for electricity. As new technologies penetrate the market in NEMS, their costs are assumed to decline to reflect the expected impact of technological learning. During each year of the analysis period, the EMM evaluates the need for new generating capacity to meet consumer needs reliably or to replace existing electric power plants that are no longer economical. The cost of building new capacity is weighed against the costs of continuing to operate existing plants and consumers’ willingness to pay for reliable service.

The EMM includes the representation of programs aimed at increasing the amount of generation coming from renewable fuels – both State and federal programs. For example, 10 States currently have State renewable portfolio standards or targets. To represent these programs, estimates of the types of renewable capacity expected to be encouraged by these programs are made and entered into the model. All cases in this analysis include estimates of new renewable energy capacity expected to be stimulated by State-level renewable programs. Over the 2002 to 2025 timeframe, these estimates include 3,488 megawatts of capacity resulting from State RPS programs, and 1,718 megawatts expected under other State renewable stimulus programs. Capacity built under State RPS programs reduces the incremental quantity needed to comply with a Federal RPS and lowers its costs. The costs of complying with the State RPS programs are not included in the costs attributed to the Federal RPS program in this analysis.

All cases in this analysis include the 10 percent investment tax credit for new geothermal and solar-electric power plants that was permanently extended in the Energy Policy Act of 1992. Treatment of the 1.8 cent per kilowatt-hour production tax credit for wind and biomass conforms to the requested analysis and is discussed latter in this section.

A. Update to the Annual Energy Outlook 2003 Reference Case

NEMS has been updated to reflect changes in electric generating capacity since AEO2003 was completed in November of 2002 and to incorporate revised expectations about near-term natural gas price trends. The following summarizes these key updates.

Generating Capacity. Within NEMS, only planned units that are reported as “under construction” are automatically included as being built during the forecast horizon. Additional renewable capacity expected from State-level mandates and programs are also included in the capacity projection. NEMS then forecasts the construction of additional unplanned capacity by type as needed to meet future demand.

For AEO2003, the information on planned generating units was based predominantly on 2001 data from the EIA-860 filings, “Annual Electric Generator Report,” which provides information from both utility and non-utility generators. The EIA-860 data was supplemented by a second data source, the NewGen database developed by Platts Database,⁵ which is updated on a monthly basis. The AEO2003 contained data capacity plans from these sources as of July 2002. The NewGen database was used to update the EIA-860 information for more recent changes in plant operating status.

Based on new information available as of the end of March 2003, about 24 gigawatts of additional planned capacity are reported as being under construction, including 8.5 gigawatts in 2002, 14.3 gigawatts in 2003 and 1.2 gigawatts in 2004. About 16 gigawatts of the additions are gas-fired combined cycle, 4.6 gigawatts are gas-fired turbines, and 2 gigawatts are dual-fired combined cycle units. The remaining 1.4 gigawatts are composed of dual-fired turbines and internal combustion units, several renewable units, and a relatively small coal unit.

Natural Gas Prices. Each month, EIA publishes 2-year projections of price, demand and supply, and stocks for each of the main energy sources in the Short-Term Energy Outlook (STEO). These projections are revised in response to observed changes in weather conditions, stock levels, and market conditions. For AEO2003, the September 2002

STEO was the basis of the short-term outlook. Since then, the natural gas price forecasts have changed significantly. For example, the average natural gas wellhead price for 2003 was projected to be $4.52 (nominal dollars) per thousand cubic feet in April 2003, about 40 percent higher than the projection for 2003 used in AEO2003. To better align with the more recent market information, the natural gas supply and price forecasts were aligned with the April 2003 STEO forecasts. In particular, adjustments were made to natural gas production, imports, supplemental supplies, storage, consumption of lease, plant, and pipeline fuel, and prices at the wellhead and the burner-tip. These adjustments mainly affect the short-term projections, but since decisions made in the later years partially depend on earlier market conditions, the longer-term projections are also affected.

B. Representing the RPS

To represent a national RPS, the EMM has the ability to require that generation from renewable facilities (including all generation from cogenerators) be equal to or greater than a specified share of total annual generation. When this is done, the most economical renewable options are constructed to meet the RPS requirement. The projected price of the renewable credits represents the incentive needed by the last increment of renewable capacity added to make it competitive with other options. The renewable credit price times the required generation in each year becomes part of the operating costs of nonqualifying facilities because sellers of power from these facilities must purchase renewable credits for them in order to comply with the required RPS share.

The proposed RPS allows new (incremental) hydroelectric capacity at existing facilities to qualify for renewable credits. While it is possible that incremental hydroelectric capacity could play a small role in meeting the RPS, EIA believes that it is not likely to have a large impact and, thus, it is not directly represented. The U.S Hydropower Resource Assessment found that upgrades at existing hydroelectric facilities could add 7.8 gigawatts to total hydroelectric capacity⁶. However, after adjusting this value to reflect environmental concerns, the report authors reduced estimated hydro potential to a maximum of 4.3 gigawatts of possible upgrades at existing sites. The report also included estimates of additional hydroelectric capacity at currently undeveloped sites, but since the proposed RPS does not provide renewable credits to new hydroelectric sites, their development will not be encouraged by the RPS. Assuming a 45 percent capacity factor for typical hydroelectric facilities, at most, 4.3 gigawatts of incremental hydroelectric facilities could provide 17 billion kilowatt-hours of additional generation, or approximately 3.7 percent of the increase in renewable generation needed to comply with this RPS. However, because cost estimates for these potential upgrades are not available, it is impossible to determine if they would be economical. If they were economical, their development would be expected to lower the costs of implementing the RPS slightly below what is reported in this paper.

To represent the specific requirements of the proposed RPS program, the annual qualified renewable share of sales called for in the proposed amendment was converted into total non-hydroelectric renewable shares. As shown in Table 1, the shares used in NEMS differ from the annual RPS shares called for in the request because the NEMS shares represent the total non-hydroelectric renewable generation share - including the generation from facilities that began operation before January 1, 2004 - required to comply with the RPS requirement (NEMS does not distinguish between generation coming from new or existing facilities so total non-hydroelectric renewable shares are used). Also, the share represented in NEMS is adjusted to account for the exclusion of utilities with sales fewer than 4,000,000 kilowatt-hours, and the exclusion of renewable generation from sales when applying the RPS share. For example, in 2008 the proposed RPS share is 2.5 percent, total electricity sales are projected to be 3,938 billion kilowatt-hours, sales from small utilities are assumed to be 711 billion kilowatt-hours, the generation from non-qualifying non-hydroelectric renewable generators (those coming on prior to January 1, 2004) are assumed to be 82 billion kilowatt-hours and the generation from hydroelectric facilities is projected to be 300 billion kilowatt-hours. Using this information, the amount of qualified renewables required is calculated as follows:

0.025 X (3,938 – 711 – 82 – 300) = 71 billion kilowatt-hours of new non-hydroelectric renewable generation.

Converting this into the total non-hydroelectric share used in NEMS gives (adding required new generation with non-hydroelectric renewable generation existing before enactment of the program, then dividing by all generation): (71 + 82) / 3,938 = 3.9 percent.

As shown, through 2015 the adjusted shares used in NEMS exceed the shares called for in the proposal because the effect of including existing non-hydroelectric renewables in the NEMS values exceeds the adjustments for excluding small utility sales and total renewable generation from the base. After 2015, however, the exclusion of total renewable generation from the baseline when applying the RPS share causes this relationship to reverse.

The request from Sen. Bingaman indicates that the price of a renewable energy credit should be capped at 1.5 cents per kilowatt-hour. Furthermore, it specifies a penalty of the lesser of 1.5-cents per kilowatt-hour or twice the average credit value may be imposed on retail electricity suppliers who do not submit sufficient renewable credits to cover their sales. For analysis purposes, this maximum 1.5-cent per kilowatt-hour/200% noncompliance penalty is treated the same as the cap on the renewable credit price. If the marginal cost of new renewable capacity in a given year is too expensive even with a 1.5 cent per kilowatt-hour credit, the required level of qualifying renewables will not be achieved. In this case, the marginal renewable credit purchaser will pay the government for non-compliance rather than build new renewables. This cap is not indexed to inflation. In previous analyses of RPS programs with allowance price caps, EIA has assumed that the price cap was indexed to inflation (that is, in real dollars rather than nominal dollars)⁷. By treating the price cap as nominal for this analysis, the real ceiling on renewable energy credit prices gets lower over time, as shown in Table 2⁸.

The current PTC provides an inflation-indexed, 1.8 cent per kilowatt-hour (in 2003) tax credit for the first 10 years of generation from qualifying facilities. Qualifying facilities include wind and certain biomass processes (“closed-loop” facilities and facilities burning poultry waste) placed in service on or before December 31, 2003. The proposed program includes a provision to extend the eligibility date for facilities placed in service on or before December 31, 2006. In addition, the proposal expands the eligible renewable technologies to include open-loop biomass at both new and existing facilities as well as new geothermal, solar, small irrigation power, and municipal biosolid and sludge recycling facilities. For biomass generation at existing facilities, the proposed PTC provisions set the value and pay-out period at 1.0 cents per kilowatt-hour and 5 years, respectively.

NEMS does not model poultry waste, small irrigation power, or biosolid/sludge technologies. EIA believes that the total resource base for these technologies is quite small relative to other renewables and the electricity market as a whole. While eligibility for the PTC may cause significant growth in these sectors relative to their current sizes, such growth would not significantly impact the renewable energy or electricity markets.

The proposed program also modifies the PTC by removing the inflation index provision. This effectively reduces the value of the PTC to the project developer over the 10-year pay-out period, as the effective tax credit does not keep pace with inflation. This is modeled in NEMS by reducing the value of the PTC each year based on the forecast growth in the Gross Domestic Product index.

Analysis Methodology - Tables

Notes and Sources