Renewable Energy (Subtitle B, Sections 1221 to 1223)

S. 1766 distributes R&D for renewable efficiency over nine areas: wind power, photovoltaics, solar thermal technologies, biomass power, geothermal power, biofuels, hydrogen-based fuels, hydroelectricity, and energy systems and storage. With one exception,³⁰ specific authorization levels within each area are not enumerated. S. 1766 would also amend the Spark M. Matsunaga Hydrogen Research, Development, and Demonstration Act of 1990, providing for authorizations totaling $420 million over the period FY2003 to FY2006 for hydrogen research and the integration of fuel cell research with a hydrogen production system. Total authorization for these renewable R&D activities in FY 2003 is $590 million, and over the period FY2003 to FY2006, the total authorized is $2.931 billion.

Wind Power. The goals of the wind power program are “to develop, in partnership with industry, a variety of advanced wind turbine designs and manufacturing technologies that are cost-competitive with fossil-fuel generated electricity, with a focus on developing advanced low wind speed technologies that, by 2007, will enable the expanding utilization of widespread class 3 and 4 winds.”³¹

The goal as stated is largely consistent with the current focus of the DOE Wind Program. It is not clear if the time target (2007) applies to the goal for “cost-competitiveness with fossil-fuel generation”, but the AEO2002 Reference Case forecasts that, in some regions, wind will be cost-competitive compared to other available generation technologies in the 2015-2020 timeframe. The EIA High Renewables Case, a forecast based on the cost goals of the DOE Office of Energy Efficiency and Renewable Energy, indicates that wind power could be competitive with fossil-generated electricity by 2007. EIA considers the Reference Case forecast as the “most likely” scenario under current policy conditions, including current levels of funding for research and development efforts. EIA provides the High Renewables Case to indicate the effect of less likely, but more optimistic, projections for the renewable technologies.³² Although not likely, it is plausible that some combination of key technology breakthrough, cumulative technology advances, or higher than expected fossil fuel prices could accelerate the timeframe in which wind power becomes competitive with other fossil-fuel generated electricity. Notably, despite the 250 percent increase in wind capacity from 1998 to 2002, installed costs for wind turbines have remained more or less constant. Performance of wind units, however, has noticeably improved over the past 5-10 years.

The challenges of using low-speed wind classes are more economic than technological in nature. Currently available wind turbine technology can be “tuned” or otherwise optimized to operate in specific wind regimes, including low-and high-speed. The global wind industry has largely developed in Denmark, a country notable for its moderate-to-poor quality wind resources (at least compared to the Northwest or Upper Great Plains regions of the U.S.). While developing technology to make Class 3 and 4 winds economically competitive raises some significant engineering challenges, it seems likely that in an “open” market (one free of subsidy or other external incentives), the higher quality wind resources will be used in preference to the lower quality. Higher quality wind classes enable higher utilization rates and/or greater ability to extract energy from wind, leading to lower costs on an output basis. Furthermore, the same technologies that improve the economics of utilizing poor wind resources will likely benefit the economics of utilizing better wind resources (although perhaps not proportionately), thus reinforcing the relative attractiveness of high-speed wind regimes.

Market pressures of deregulation also will tend to lessen the value of low-quality local resources relative to the high-quality resources that are abundant in a few, well-defined geographic regions of the country. In a regulated market, wind resources are more likely to compete against a finite set of local generation options, and the value of reducing the cost of class 3 or 4 winds to compete with some locally high-cost conventional resources may be well justified. However, in a deregulated market, low-quality wind resources have to compete against low-cost conventional technology and wind resources from a much broader geographical area. Finally, the credit-trading process associated with the RPS provision of this legislation will create further market pressures to meet the target by utilizing high-quality resources located anywhere in the country in preference to lower-quality local resources.

Photovoltaics. Section 1221 of S. 1766 directs the Department of Energy to “conduct balanced energy research, development, demonstration, and technology deployment programs to enhance the use of renewable energy.” The program goal stated in Section 1221 for the photovoltaic program is to develop, in partnership with industry, total photovoltaic (PV) systems with installed costs of $4000 per peak kilowatt by 2005 and $2000 per peak kilowatt by 2015. PV systems produce electricity by the direct conversion of solar rays to electricity through a semi-conductor cell.

In the case of customer-sited PV systems, unsubsidized installed prices for on-grid systems currently range from $7,000 to $12,000 per peak kilowatt.³³ At the other end of the price spectrum, Sacramento Municipal Utilities District (SMUD) has reported total installed costs to the customer as low as $3,500 per peak kilowatt. In addition to price advantages due to large volume purchases, the SMUD program includes subsidies in the form of an additional “buy down” provided through SMUD’s Public Goods Funds with some additional financial support provided to SMUD through the U.S. DOE/Utility PhotoVoltaic Group TEAM-UP program.³⁴

The feasibility of reaching the S.1766 cost goals for PV systems depends on the intended scope of the goals. The 2005 goal of $4,000 per peak kilowatt does not seem within reach if purchases are not subsidized, though subsidy programs such as SMUD’s, or State and/or local incentives such as California’s cash rebates of up to $3.00 per watt may help to meet the goal. A reduction of 50 percent or more – from current levels of $7,000-$12,000 to $4,000 per peak kilowatt – in the installed costs for widely available, unsubsidized PV systems seems unlikely by 2005.

Reaching an installed cost of $2000 per peak kilowatt by 2015 would require significant cost reductions, over and above any potential subsidies. The 2015 goal specified in S.1766 represents an average cost reduction of 9 percent per year from 2001 to 2015 using a representative, current retail price of $8000 per peak kilowatt. Using the lowest installed costs to the customer reported by the SMUD PV program, which includes subsidies, still requires an annual cost reduction of at least 4 percent to meet the 2015 goal. Substantial declines in the price of PV systems are not unprecedented. The lowest price for PV systems in 1995 was less than half the system price in 1985. However, with the expiration of Federal tax credits in 1985, PV systems were no longer competitive with purchased electricity in most instances, and an increasing share of U.S. PV module production has been exported. Conversely, unsubsidized system prices have recently seen little decline due to increased worldwide demand for PV modules and constrained manufacturing capacity. Prices for balance-of-system components (e.g. inverter, installation and wiring) that account for about half of the system costs have remained stable as well. The longer the current trend continues, the steeper price declines must be ­ in both module and balance-of-system components -in order to realize the 2015 cost goal, making its achievement even more difficult.

Utility-scale PV systems, also called “Central Station PV” can achieve somewhat better economies-of-scale than roof-top systems, and thus have considerably lower system costs. However, while these systems achieve lower costs, they also must compete against considerably lower “wholesale” power costs (that is, power costs at the transmission bus-bar), rather than the retail costs that customer-sited systems compete against. Because of their prohibitive cost relative to other wholesale power options, there has been little market demand for central-station PV. However, EIA estimates system costs for such a configuration are already below the $4,000/kW target set for 2005. EIA further expects that continued demonstration projects and other subsidized installation of these systems could be sufficient to reduce costs to about $2,300/kW by 2015, although even this cost is not likely to make these systems competitive on an unsubsidized basis in the wholesale market. Given the apparently poor prospects for central-station PV, it is uncertain whether sufficient market activity (including demonstration and other subsidized projects) in this sector would actually occur to realize the projected price path. However, if such market activity does occur, it is plausible that a successful research and development program on top of normal market learning could reduce costs to the $2,000/kW target for 2015, at which price the systems would still likely be uncompetitive in a deregulated wholesale power market. Niche applications for PV will remain, in remote areas lacking access to electric system infrastructure, in remote communication relay stations, and in electronic equipment.

Solar Thermal. The goal of the solar thermal electric systems program is “to develop, in partnership with industry, solar power technologies (including baseload solar power) that are competitive with fossil-fuel generated electricity by 2015, by combining high-efficiency and high-temperature receivers with advanced thermal storage and power cycles.”

Solar thermal electric power systems, also called concentrating solar power (CSP), is a class of technologies that concentrate solar rays to produce thermal power generation (such as through a steam turbine or other external-heat source engine). It has several operating characteristics that make it an attractive technology relative to photovoltaic technology; in particular, it has a higher conversion efficiency (the ratio of “watts out” to “watts in”), can easily incorporate thermal storage to improve dispatchability (that is, for some additional cost, it can be used when needed rather than just when the sun is shining), and it can also easily incorporate a back-up fuel source. However, relative to fossil-based generation technologies, CSP faces substantial economic hurdles.

Currently, only one commercial solar thermal plant exists in the U.S. (actually a series of small facilities generally considered to be a single plant), which was constructed, under heavy subsidies, in California during the 1980s. Several technologies are undergoing research and development efforts to address key developmental barriers, especially cost. EIA currently estimates the levelized cost of a new “commercial” CSP unit at about 12 cents per kilowatthour. Total overnight capital costs for the technology are $2,539/kW (2000 dollars). With no near-term commercial growth expected with current costs, EIA expects cost declines to primarily come from continued research, development, and demonstration activity. Based on the currently projected level of activity, and assuming no change in the cost and performance basis of the technology, EIA expects the cost to decline to about 10 cents per kilowatthour late in the forecast (all costs in year 2000 dollars). If the cost and performance targets of the EE/EPRI Renewable Energy Technology Characterizations report could be met (especially the addition of significant storage), ³⁵ the 2015 cost could be as low as 7 cents per kilowatthour (Figure 2). At this time, EIA projects the cost of advanced combined cycle units remaining at just over 4 cents per kilowatthour by 2015. Reference Case projections for solar thermal technology imply about a 1 percent per year cost decline; DOE projections imply about a 3 percent per year cost decline; by comparison, the S. 1766 goal of cost-competitiveness implies a cost decline of about 7 percent per year.

With no new commercial installations for over a decade and little recent demonstration activity, it is difficult to accurately gauge the potential for such significant, sustained cost decreases or to estimate the possibility of a single “breakthrough” advance that could result in such a decline. Much of the cost improvement forecast in the EE/EPRI cost projections (which are half the legislative target) relies on integration of thermal energy storage into the systems. Given the inefficiencies, both economic and performance, inherent in all energy storage systems, achievement of these targets seems unlikely in the 2015 timeframe.

Biomass Power. Section 1221 (b)(4) further states, “The goal of the biomass program shall be to develop, in partnership with industry, integrated power-generation systems, advanced conversion, and feedstock technologies capable of producing electric power that is cost-competitive with fossil-fuel generated electricity by 2010, together with the production of fuels, chemicals, and other products under paragraph (6)”.

DOE’s Biopower program is working with industry to reach the following goals: “Improve the efficiency of the energy system; Ensure against energy disruptions; Promote energy production and use in ways that respect health and environmental values; Expand future energy choices; and Cooperate internationally on global issues”. The technologies being considered are biomass cofiring, biomass gasification, and modular biomass systems.³⁶ Additional program areas include bioenergy feedstock development and technology supporting elements (which includes energy conversion research, regional biomass energy programs, international activities, and a bioenergy initiative).³⁷ DOE estimates that this would result in 45,000 MW of new biomass capacity by 2020 (cofiring 26,000 MW, industrial pulp and paper 7,000 MW, biomass gasification 6,000 MW, and modular systems 6,000 MW). The EIA S.1766 RPS Case indicates that by 2020 biomass capacity is projected to grow to approximately 24,600 MW,³⁸ or 55 percent of DOE’s capacity goal.³⁹ The AEO2002 Reference Case, which represents an unsubsidized growth scenario, shows biomass capacity at about 11,000 MW by 2020, or 24 percent of DOE’s capacity goal. In the AEO2002 High Renewables Case, which represents a more optimistic resource availability scenario, biomass capacity grows to about 13,000 MW or 29 percent of DOE’s capacity goal. An examination of the corresponding levelized costs for biomass and gas-fired advanced combined cycle technology (Figure 2, p. 16) indicates a persistent cost differential over the forecast period. Therefore, both DOE’s capacity goal of 45,000 MW and the legislative goal of cost-competitiveness appear difficult to achieve over the mid-term.

Geothermal Technology. The goal of the U.S. DOE’s geothermal program is “to develop, in partnership with industry, technologies and processes based on advanced hydrothermal systems and advanced heat and power systems, including geothermal heat pump technology, with a specific focus on (A) improving exploration and characterization technology to increase the probability of drilling successful wells from 20 percent to 40 percent by 2006; (B) reducing the cost of drilling by 2008 to an average cost of $150 per foot; and (C) developing enhanced geothermal systems technology with the potential to double the useable geothermal resource base.”

These goals echo program goals that have been pursued for a number of years. And progress in increasing success rates and lowering drilling costs appears to be occurring. However, the highly ambitious goals, the scale of current public R&D investment, and minimal commercial geothermal growth all suggest the difficulty in meeting the S.1766 geothermal R&D goals within the demanding time constraints described above. Breakthroughs necessary to double the successful geothermal drilling rate by 2006 have yet to be identified or demonstrated. Prospects of cutting drilling costs 50 percent in eight years -from an estimated $300 per foot today – appear difficult to achieve.

Biofuels (Cellulose Feedstocks). S. 1766 includes a research program to improve conversion technology for cellulose feedstocks. The stated goal is liquid or gaseous fuel that is cost competitive with petroleum-based fuels. EIA incorporates the use of biomass for electricity generation and ethanol production in the Annual Energy Outlook 2002 (AEO2002).

Table 4 summarizes two sets of assumptions about cellulose ethanol technology. The Reference Case assumptions are those that EIA thinks are most likely. The high technology assumptions are more optimistic and are part of the AEO2002 High Renewables side case. This analysis assumes that the excise tax exemption for blending ethanol into gasoline remains in place from 2005 through 2020 at a nominal $0.51 per gallon of ethanol blended.⁴⁰ Because ethanol has only about 2/3 the Btu content of gasoline, the equivalent of a gallon of gasoline for use in an internal combustion engine is 1.5 gallons of ethanol.

Cellulose ethanol cannot compete on price with gasoline without the aid of the blenders’ tax credit. With the tax credit, cellulose ethanol’s effective price to buyers is projected to be $0.01 per gallon less than gasoline in 2020 under the Reference Case. Under the high renewable case, cellulose ethanol’s effective price is projected to be $0.05 lower in 2010 and $0.24 lower per gallon gasoline equivalent in 2020. While cellulose ethanol could be described as price-competitive under these conditions, it cannot be said to be cost-competitive, because the equivalent amount of ethanol costs more to produce than gasoline regardless of time and technology. The subsidy is required to make ethanol price-competitive.

Higher conversion rates could result from the proposed research program, but the conversion rates and capital costs assumed in the high renewable case already reflect an ambitious research program. It appears difficult to meet the goal of cost-competitiveness with gasoline.

Hydrogen-based Fuels. The S. 1766 goals for the hydrogen program are modest, “to support research and development on technologies for production, storage, and use of hydrogen, including fuel cells and, specifically fuel cell vehicle development.”

Much work, however, remains before hydrogen production can be pursued efficiently. Currently most of the hydrogen used in industrial processes is produced from natural gas through a steam reforming process for about $7 to $8 per million Btu, several times more than the natural gas itself. New photobiological and photoelectrochemical (PEC) processes for producing hydrogen are being researched and tested: one recent PEC water-splitting test yielded 12 percent efficiency using concentrated light.⁴¹ Hydrogen storage systems for transportation also face significant economic challenges. Hydrogen has very low energy density at normal temperature and pressure conditions and consequently, mobile fuel tanks will have to operate at very high pressure. “No approach currently satisfies all the efficiency, size, weight, cost, and safety requirements for transportation or utility use,”⁴² though research is continuing. Hydrides are capable of storing hydrogen at sufficiently high density, but additional research into appropriate alloys which would release the hydrogen at low temperatures is necessary. In the long run, beyond 2020, hydrogen could be an important source of energy in the United States, but in the near term, economic applications do not seem likely.

Hydroelectric Power. S. 1766 Subtitle B, Section 1221 (b)(8) sets the goal “to develop, in partnership with industry, a new generation of turbine technologies that are less damaging to fish and aquatic systems.”

The Department of Energy is partnering with industry and progressing in developing turbines that are less damaging to fish and aquatic systems. Because S.1766 is very general and without explicit deadlines, current progress appears to meet the stated goal for hydroelectric turbine advances.

Electric Energy Storage and Efficiency. Paragraph (9) of Section 1221 envisions several types of R&D projects whose goal is to develop, in partnership with industry, advanced technologies to increase the efficiency of electric transmission, to make better use of distributed generation resources, to develop superconducting materials for use in transmission, distribution cables, and generation, and to develop real-time system control technologies linking generation, transmission, distribution, and end-use consumption. These technologies generally seek to reduce losses associated with generation and transmission of electric power, thereby reducing fuel use and emissions associated with fuel combustion.

Of these technologies, superconductivity holds the most promise for yielding significant efficiency gains. Before the discovery of high temperature superconductive materials in 1986, superconducting materials had to be cooled to below –400° F; more recently, materials with the appropriate superconductive properties have been developed at temperatures near –200° F, an advancement that reduces cost by replacing liquid helium with relatively inexpensive liquid nitrogen. Developing cost-effective, long-length superconducting ceramic wire represents the biggest challenge and potentially the biggest return.

Many of these technologies have been successfully demonstrated and several have recently received DOE support for field testing and development. For example, a 77 megawatt ampere (MWA) pre-commercial superconducting cable system will be installed in a substation on Long Island, N.Y., to demonstrate that long-length superconducting cable can reliably improve power delivery in congested urban areas. In Ohio, a 1000-foot long, 3-phase, superconducting cable will be installed at the AEP substation at Bixby Road, in Columbus, replacing an existing oil-filled, underground power cable with limited current-carrying capacity.⁴³ And in Detroit, 14,000 customers of Detroit Edison are served in part by 1,200 feet of superconductive cable routed through the Frisbie Substation as of May 2001.

The cost of superconductive materials is quite high. American Superconductor, which supplied the wire for the Frisbie Substation project, sells the wire for about $200/meter; copper wire with similar capacity features sells for about $25/meter.⁴⁴ It is possible that high-temperature superconductive materials could be deployed in some high value applications,⁴⁵ but further cost reductions will be needed to permit broad applications in the mid-term.

Notes and Sources