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Resource and Employment Impact of a Renewable Portfolio Standard in the Tennessee Valley Authority Region Jack Barkenbus1, R. Jamey Menard2, Burton C. English3, Kim L. Jensen3 July 2006

1 Executive Director, Energy, Environment and Resources Center, University of Tennessee, Knoxville 2 Research Associate, Department of Agricultural Economics, University of Tennessee, Knoxville 3 Professor, Department of Agricultural Economics, University of Tennessee, Knoxville

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I. Abstract This report calculates the amount and nature of renewable energy production in the Tennessee Valley Authority (TVA) region associated with Congressional passage of a renewable portfolio standard (RPS) and examines the employment consequences derived from this initiative. Under a 10-percent RPS requirement by 2020, TVA would have to account for roughly 19.7 billion kilowatt hours (kWhs) of renewable energy output (increasing the magnitude of its Green Power Switch program some 250 times). A reasonable estimate of what TVA could bring on-line by 2020 is 15.2 billion kWhs, with the rest of the obligation purchased through renewable energy credits (RECs). The majority of the output from renewables would come from co-firing biomass at existing TVA coal-fired power plants. Using an input-output model, it was calculated that nearly 45,000 jobs would be created across the region as a result of the initiative. II. Introduction Governments across the globe are using a variety of policy mechanisms to encourage the utilization of renewable energy resources for the production of electricity. These mechanisms, along with technological advancements, portend a future in which renewable energy resources are transformed from niche sources of energy to mainstream providers of our electricity. This transformation will not occur suddenly and not without considerable effort, but it can be expected to evolve over time. The United States has favored the renewable portfolio standard (RPS) approach as a tool for advancing renewable energy—at least at the sub-national level—as 20 states, plus the District of Columbia, currently have RPS requirements embedded within legislation, and another two have non-binding, administrative, RPS targets (see Figure 1). In three separate Congressional sessions, the U.S. Senate has passed bills requiring a national RPS, but in each session, the House of Representatives has not concurred, and the measure has vanished from the legislative session in conference committee. The absence of executive branch support for an RPS has been a critical element in its rejection. An RPS consists of the establishment of a quantitative requirement for the production of electricity from renewable energy resources over an established and explicit time frame. State-based quantitative requirements vary significantly, with some including existing renewable resources within the mandate and others excluding them. U.S. Senate versions have consistently been pegged at a 10-percent requirement for 2020 (with interim, graduated targets expected as well). This may seem exceedingly modest to some, but given that renewable resources today provide only 2 percent of the country’s electricity—when excluding existing hydropower generation—it constitutes a significant commitment to clean, renewable, resources. In its most recent Annual Energy Outlook, the U.S. Energy Information Administration (EIA) forecasts that in the absence of any RPS, or other major policy measures, nonhydroelectric renewable resources would still constitute only 4 percent of electricity generation in 2030.1

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An RPS, therefore, is a technology-forcing policy tool not dependent upon market-based prices. This does not mean that market prices do not play a role in the choice of renewable energy but simply that the quantitative requirement is established independent of economic tradeoffs associated with conventional electricity production. Despite the rejection of a federal-government imposed RPS to date, the chances of passage in the future appear favorable. Approximately 50 percent of the nation’s electricity is currently generated from coal, and the environmental impacts associated with this generation (particularly those related to carbon emissions and global climate change) are becoming increasingly unacceptable. Generation of electricity from natural gas and uranium poses its own drawbacks. Technological advances across many renewable resource technologies mean that electricity consumers may not be put at undue financial risk when these technologies are deployed more widely. This certainly makes an RPS more palatable to decision makers. And, in all cases where states strike out in a policy direction on their own, there eventually will be a push for national uniformity. State initiatives are often a necessary catalyst for action, but commercial operations will always argue for consistent and uniform standards. The real question surrounding a federally based RPS, therefore, is not whether one will be enacted but rather when and it what form. The most likely nature of such an RPS will be discussed shortly, but it seems prudent to assume a 10-percent renewable requirement by 2020. This falls considerably short of the level desired by some environmentalists but is probably a reasonable number around which political consensus can be forged. And, of course, there is nothing preventing higher levels of renewables to be used in the future if market conditions or other policy factors (e.g. a mandatory carbon-reduction program) intervene. Hence while a 10-percent target may be seen as a “ceiling” by many today, it may end up being no more than a “floor.” III. State-level RPSs As illustrated in Figure 1, RPSs have been enacted in every region of the country except for the Southeast. As of late 2005, another seven states (Utah, Nebraska, Louisiana, Florida, Virginia, New Hampshire, and Vermont) were legislatively considering RPSs. At present, over half the U.S. population resides in states with RPSs.2 As noted previously, state RPSs differ markedly from one another. They differ with respect to quantitative requirements, time frames, and perhaps most important, what constitutes a renewable resource for inclusion in the requirement. Some states disallow existing renewable resource generation entirely, while others permit it to be counted toward the quantitative target. The actual enumeration of what constitutes a legitimate and desirable renewable resource varies (some states, for example, allow municipal solid- waste-to-energy projects to count, whereas others do not). And some states make distinctions among allowable renewable resources by requiring a certain percentage of the target to be met by most-favored renewables (so-called “carve outs”). A few states

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(Hawaii, Pennsylvania, and Nevada) are even counting energy efficiency measures toward their RPS goals. Little is simple or self-evident in the establishment of an RPS, as choices revolving around fuels and time frames appear frequently in the process of formulating a consensus-based RPS. Putting all of that aside for the moment, it has been estimated that if all the existing state efforts were faithfully implemented, it would lead to the deployment of between 40 and 64 gigawatt electric (GWe) generating capacity nationally from renewables by 2020.3 This is certainly much more than a business-as-usual scenario would produce, and it is estimated that it could generate $53 billion in renewable resource investment.

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April 2006

Figure 1: Renewables Portfolio Standards

Source: North Carolina Solar Center www.dsireusa.org

Renewables Portfolio Standards

State Goal

☼ PA: 18%¹ by 2020☼ NJ: 20% by 2020

CT: 10% by 2010

MA: 4% by 2009 + 1% annual increase

WI: requirement varies by utility; 10% by 2015 Goal

IA: 105 MW

MN: 10% by 2015 Goal +Xcel mandate of

1,125 MW wind by 2010

TX: 5,880 MW by 2015

*NM: 10% by 2011

☼ AZ: 1.1% by 2007

CA: 20% by 2010

☼ NV: 20% by 2015

ME: 30% by 2000

State RPS

*MD: 7.5% by 2019

☼ Minimum solar or customer-sited requirement* Increased credit for solar

¹PA: 8% Tier I, 10% Tier II (includes non-renewable sources)

HI: 20% by 2020

RI: 15% by 2020

☼ CO: 10% by 2015

☼ DC: 11% by 2022

☼ NY: 24% by 2013

MT: 15% by 2015

*DE: 10% by 2019

IL: 8% by 2013

VT: RE meets load growth by 2012

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IV. A Federal RPS The enactment and implementation of a national RPS would lead to the deployment of many more renewable resource technologies than the cumulative total from today’s roster of state RPSs. The Union of Concerned Scientists estimates that a 10-percent requirement would increase renewable energy generating capacity to 80 GWe by 2020.4 It is important, therefore, to try to anticipate what the major features of a national RPS might be. The versions embodied in U.S. Senate legislation present a logical basis for informed speculation.5 Major features include:

• A 10-percent requirement out to 2020 would be imposed on “major retail electric suppliers.”

• The requirement would be denominated in credits, with one credit equal to 1

megawatt hour (MWh) generated. The reason for this distinction is to allow for the trading and buying of credits (in other words, each major retail supplier would not be required to actually generate MWhs, but could purchase credits generated and sold by other suppliers). An assumption in establishing such as system is that it will be more costly in some regions of the country to generate renewable electricity than in others and that a trading system is a way of evening out the costs.

• Renewable energy sources eligible for credits would be solar, wind, geothermal,

ocean energy, biomass (excluding municipal solid-waste burning), and small and incremental hydropower. “Carve outs” for particular types of renewable energy have not been part of federal legislation; nor has credit been accorded energy efficiency measures.

• New renewable energy sources would be eligible for credits. Existing renewable

energy sources (including solid-waste-to-energy projects) would not be awarded credits (hence would not be tradable) but could be subtracted from the retail suppliers’ requirements.

• It is generally acknowledged that quantification of energy production or

generation is a more straightforward method of RPS accounting than basing such a system on installed generating capacity.

Whether these features will be found in future RPS legislation cannot be guaranteed, of course. They do, however, provide a foundation on which to assess how a federal RPS might affect the Tennessee Valley Authority (TVA). V. TVA TVA is a federal agency serving roughly 8.6 million electricity consumers in portions of seven states (Tennessee, North Carolina, Kentucky, Georgia, Alabama, Mississippi, and

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Virginia). TVA’s power service area covers 80,000 square miles in the southeastern United States and is shown in Figure 2.

GeorgiaAlabama

Kentucky

Tennessee

Mississippi

Illinois

Missouri

Indiana

South Carolina

North CarolinaArkansas

Ohio

Virginia

West Virginia

Louisiana

Figure 2: Tennessee Valley Authority Region Approximately 85 percent of the electricity generated by TVA is sent to locally owned distributors who transmit it to end-users. One can technically say that the “major retail electric supplier” designation in RPS versions to date would apply to each of the TVA distributors, but, in fact, electricity generation resides with TVA, and it is likely that the RPS requirement will, by default, fall to TVA. Most of the remaining electricity that TVA does not send to distributors in the region is sent directly to large end-users (54 industrial facilities and 8 federal installations). In some RPS versions, government-owned utilities and electric cooperatives are exempted from the RPS mandate. Since such a provision would amount to no less than exempting 25 percent of the electricity market, we should not expect this provision to be part of a final federal RPS. In fiscal year 2005, TVA transmitted 171 billion kWhs of electricity to customers in its seven-state region. It generated 157 billion of that total and purchased the balance from suppliers outside the region. Nuclear and coal generation accounted for 90 percent of the generated total, with hydropower accounting for approximately 9 percent.

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The figure of merit for TVA in RPS deliberations is the amount of power it transmits to customers, and not that which it simply generates itself. Calculation of TVA’s RPS obligation, therefore, begins with the 171 billion kWh total. To determine what TVA’s obligation will be in year 2020, we must make some assumptions about growth rates. Some within TVA assume a 2.4-percent per year growth rate. Others within TVA are using a lower growth rate of 1.4 percent per year out into the foreseeable future. TVA conducted an integrated resource planning process, published as Energy Vision 2020, in the mid-1990s, during which it made long-term demand forecasts out to 2020.6 In the analysis, TVA projected different demand scenarios with low, medium, and high estimates of demand. The low scenario projected no further demand out to 2020. That projection has already been invalidated. The high scenario envisioned over a 300 billion kWh requirement in 2020 (a 75 percent increase over currently-supplied totals). That is, of course, still possible, but very unlikely. The medium projection has, in fact, tracked with actual results to date and foresees a demand of 219 billion kWh in 2020. This is roughly consistent with a 1.7-percent growth rate. For the purposes of this study we will use a growth rate of about 1.5 percent meaning that 215 billion kWh will be transmitted to TVA customers in 2020. We anticipate a mandatory-carbon reduction program being imposed by the federal government within the next few years that will set in motion a rather ambitious energy-efficiency effort within TVA and its customers. Using previous RPS model assumptions, TVA would not be able to generate credits for its existing renewable resource generation. It would, however, be able to subtract this generation from its baseline total. The amount of hydropower generated is, of course, variable dependent upon hydrological conditions. In 2005, TVA generated about 17.5 billion kWh through its system of 29 hydropower plants and its pumped storage. If we subtract this from expected 2020 demand, we get a 197.5-billion kWh demand requirement. This total has to be reduced still further by TVA’s existing Green Power Switch program, based on selling renewable-based electricity to consumers willing to pay extra for the service. The Green Power Switch program currently is a combination of wind, solar, and wastewater gas. As of 2005, total electricity generated through this program was running at approximately 80 million kWh per year. This total barely registers a change in TVA requirements, moving the total down slightly to 197.4 billion kWh. To obtain a final TVA number or target under a federal RPS we simply take 10 percent of the total just derived. That number comes to 19.7 billion kWhs. For the purposes of this study, we seek to answer how TVA would meet this responsibility by 2020. While a federal RPS will probably come with interim quantitative goals, no attempt in this study is made to investigate this level of detail. To fully appreciate the magnitude of the challenge TVA faces in meeting such a requirement, it is useful once again to note that TVA’s current Green Power Switch program produces just 80 million kWh per year. This means that TVA must expand that program fully 250 times over its current size by 2020—by no means a trivial undertaking

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(the utility with the most RPS-relevant renewable output in 2005—Austin Energy—produced just 435 million kWh).7 TVA will be forced to mainstream its renewable energy efforts, transforming them from a niche program to a full-body production operation, with all the resource-intensive requirements that such a switch entails. No assumption is made in this study as to whether TVA will build and operate renewable energy initiatives, contract for the services, or simply provide incentives for generation (for which it can claim credit, as currently carried out through the Generation Partners component of the Green Power Switch program). Regardless, it would be a transforming experience for the agency, which up to this time has always evaluated renewables in the context of the costs from conventional energy production. In such a context, the relatively high costs of new renewables have always limited their application. The RPS presents a completely different context in which renewables compete with one another (potentially on the basis of several criteria, not solely cost) and not against conventional sources of supply. The economic implications of such a transformation are uncertain. Most studies claim that the impact of an RPS on electricity rates will be negligible since renewables will still be a small component of the generation rate base, and because natural gas prices would probably fall somewhat (from its displacement by quantities of renewables). What is clear is that the fear TVA has consistently expressed—that rising costs and rates (occasioned by more renewable energy input into its supply system) would put it at a competitive disadvantage with neighboring utilities—would not apply, since neighboring utilities will be required to meet the same RPS requirements as TVA. VI. Meeting the Demand TVA’s challenge, therefore, will be how to meet a 19.7-billion kWh demand through the use of renewable resources. While the Southeast United States is generally thought to have poorer renewable energy prospects than many other regions,8 the TVA region, as a whole, has certain advantages and disadvantages with respect to its resource endowment. Clearly there is no opportunity, whether for good or ill, to utilize geothermal energy or ocean energy. Hydropower is also a limited resource: the region will not see the construction of another major dam as that was an enterprise for another, past, era. The magnitude of other renewable resources—solar, wind, waste gas, and biomass—is fundamentally not an issue. If fully exploited, they could easily meet the projected demand. The issue, however, comes down to how fast these resources can be exploited, at what cost, and with what public opposition. The renewable-resources industry is at a nascent stage of development today, and it will take time to put the human, capital and financial infrastructure in place to generate significant levels of energy. Solar resources are unevenly distributed across the United States as seen in Figure 3. The National Renewable Energy Laboratory (NREL) characterizes the areas within the TVA region as either good or very good, though these resources do not match the potential of excellent that characterizes much of the Southwest. This comparison among

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regions, however, has its limitations. The solar energy reaching the Earth is so vast that a region does not have to be ideally situated to take advantage of it. The fact that Germany, a country with relatively little solar insolation, is the most aggressive exploiter of this resource today is testimony to the vastness of the resource (and the German’s willingness to pay for the high cost of solar today). It can, therefore, be stated with some confidence that solar is an abundant resource in the TVA region. The Southeast region is not thought of as a propitious place for wind. Figure 4 again shows how the region compares with other regions of the country in terms of resource availability, and it is true that wind resources are in greater abundance elsewhere. Nevertheless, there are strips along the Cumberland and Appalachian Mountains where large amounts of wind can be harvested. TVA has encountered public opposition in some areas where it has sought to locate windmills, but the study assumes that at least some of this opposition can be overcome, or avoided, once an RPS is in place. The biomass and waste gas potential in the TVA region is extensive. Figure 5 gives a nationwide perspective for biomass. A Department of Energy study of forest residues, agricultural residues, and potential energy crops estimates that those resources in Tennessee alone could generate an estimated 22.2 billion kWh of electricity--by itself, well above TVA’s requirement under a federal RPS.9 We also assume in this study that methane from waste products will be considered a legitimate renewable resource. The TVA region has a large number of landfills and wastewater treatment plants where methane can be captured to produce electricity. Animal waste is also a form of biomass that can be harvested.

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Source: National Renewable Energy Laboratory

Figure 3: Solar Resource

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Source: National Renewable Energy Laboratory

Figure 4: Wind Resource

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Source: National Renewable Energy Laboratory

Figure 5: Biomass Resource

In short, despite being unable to draw from some renewable energy resources that other regions of the country have access to, the TVA region is not lacking a substantial renewable resource base. A study TVA itself conducted, concluded that the agency could draw upon roughly 3,000 MWe generating capacity from renewables, both within and directly adjacent to the TVA service area.10 This study concludes that more is possible but that this amount constitutes what could be brought on-line within our 14-year working time frame. Of course, TVA has the choice of generating (or contracting for) its own electricity from renewables or entering the trading system and buying (or selling) credits, from outside the region, to move toward or achieve its quantitative requirement. VII. Energy Choices It may appear self-evident to some that TVA would follow a “least-cost” strategy in fulfilling its renewable mandate. But it may be wise for TVA to include other criteria than simply cost in its selection methodology. Clearly the public does not view all renewables as equal in terms of their desirability. Public surveys have consistently revealed that solar power is the most desirable renewable, with wind seen as only slightly less desirable.11 Biomass, while still seen as generally positive, does not enjoy the same level of popularity as solar or wind. Solar photovoltaic systems unfortunately represent the most expensive renewable, at least in the TVA region. Hence a “least-cost” strategy would delegate solar generation to the end of the line and perhaps omit it entirely if cheaper power could be obtained from the import of renewable energy credits (RECs), or so-called “green tags.” (See Appendix B for further description of RECs). It would probably be inappropriate for TVA to pursue that strategy, however, since solar power is such a strong symbol of what renewables embody. This has certainly been recognized in TVA’s Green Power Switch program, which contains a modest amount of solar scattered throughout the region. We assume in this study that TVA will continue to want to include solar in its renewable mix, if only to meet public expectations. It will also be shown that TVA will have to rely on RECs to meet its target, regardless of cost. A determined and ambitious renewable program is likely to go far in meeting TVA’s requirements under an RPS, but it is unlikely to fulfill the total requirement. Hence, TVA will import a certain number of RECs, either in a bundled or unbundled form (again, see Appendix B for details). A bundled REC means that TVA will import both the energy and its renewable energy premium. An unbundled REC means that TVA will simply pay for the renewable energy premium. It may, in fact, turn out that an unbundled REC, combined with more coal generation from TVA facilities, will be a cheaper option than many of the renewables that TVA can, in fact, bring on-line. A “least-cost” strategy, therefore would argue for less renewable energy generation in the region than could reasonably be implemented. Again, it is important that other criteria be considered. As desirable as RECs may be, they will not present the employment options in the region that come with indigenous supplies. For this reason, we assume that TVA will do all it can to bring renewables in the region on-line and that RECs will be considered only to fill in the gap between what can be brought on-line and TVA’s required totals.

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VIII. Renewable Energy Generation and Employment Table 1 provides this study’s assessment of how TVA would meet its 10-percent requirement by 2020. The employment figures found in subsequent sections of this report are based on a breakout of these numbers. The amount of kWh generated by each renewable energy source is simply a reasonable estimate of levels of magnitude. No precision is implied in these estimates, and how they were derived is set forth in separate resource sections that follow. The locations assumed for the placement of each technology can be found in Appendix A Table 1: kWh generated RPS Requirement 19.7 billion Renewable Energy Generation

• Incremental Hydropower 1,567,802,000 • Wind 2,342,800,000 • Solar 10,512,000 • Landfill Gas 261,503,500 • Wastewater Gas 120,998,000 • Biomass

--Biodiesel 700,000,000 --Animal Waste 560,640,000

• Biomass (co-fire) --Ag. Residues 181,682,622 --Energy Crops 7,024,478,024 --Forest Residues 1,124,248,953

--Mill Residues 1,351,177,224 ____________ Total 15.25 billion

Renewable Energy Purchase

• RECs 4.45 billion _____________ Final Total 19.7 billion

As Table 1 demonstrates, TVA can be expected to fulfill nearly 80 percent of its RPS mandate through the generation of renewables in the region. Though this total can be achieved through the use of known technologies (no technical breakthroughs are assumed) it will not be an easy feat. Energy crops (switchgrass) co-fired in coal boilers, for example, will have to account for

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nearly half the total, and there is no co-firing of switchgrass taking place at TVA plants today. An entire industry will need to be created to meet the levels of generation envisioned in this study. Even with such ambitious efforts, TVA will still need to purchase a substantial number of RECs to meet its requirement. If these unbundled RECs cost anywhere from a $5 to $15, as anticipated, TVA will have to pay between $22 million and $66 million in 2020 and every year beyond, depending upon how quickly indigenous renewable resource generation can be increased. In addition to accounting for the totals in Table 1 through discussion in subsequent sections, we also explore their employment impacts within the TVA region. We do so through the use of a well-recognized economic impact modeling system, termed IMPLAN.12 IMPLAN is an input-output tool used by hundreds of public and private institutions to estimate potential employment impacts of actions. Output from the model includes descriptive measures of the economy for over 500 industries in the U.S. economy based on the North American Industry Classification Systems (NAICS). Employment is defined as the estimated number of both full-and part-time salary and wage employees as well as self-employed individuals.13 The model also estimates multipliers for predictive purposes. For this analysis, the multipliers will be used to measure the response of the economy in terms of jobs, based on an exogenous change (i.e., growth in a renewable energy industry such as solar). Multipliers measure the difference between the initial impact of an exogenous change in final demand (final use and purchased goods and service produced by industries) and the total impacts of change. The measure of the initial impact resulting from a change in final demand is called a direct impact. As a result of the direct impact, input supplying industries respond to this change by increasing their production processes in to satisfy this new demand (assuming the final demand change is positive). The activities of input-suppliers to satisfy this final demand change are called indirect impacts. Further, this increase in production processes leads to increased expenditures of new household income and inter-institutional transfers generated from the direct and indirect impacts of the change in final demand for a specific industry. These are induced impacts. Total impacts are the sum of direct, indirect, and induced impacts.14 With the development of a new renewable energy industrial complex, the economic structure of the region could change. With increased demands for inputs, economic activity would also increase potentially, resulting in additional supporting industries locating within the region and less leakage, or money going outside the region. No attempt has been made within IMPLAN to capture these potential changes, although discussion of this development appears in a later section of this report. Quantitative estimates of employment impacts provided in this section, therefore, should be viewed as conservative. To project the employment impacts of providing energy from renewable energy sources, IMPLAN was augmented with input from existing renewable electricity sectors. They include the following:

• animal waste from poultry litter was used to provide feedstock for new wood-fired power plants;

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• soybeans were used to provide feedstock for new biodiesel facilities;

• biomass feedstocks (agricultural residues, switchgrass, forest residues,

and mill residues) to be co-fired with coal in existing power plants;

• incremental hydropower (existing hydroelectric facilities engineered/retrofitted for increased efficiency or additions of new capacity);

• methane generation from landfills and existing wastewater municipal

treatment plants;

• solar energy from residential or commercial photovoltaic systems, and;

• wind turbines. Representative engineering conversion technologies to produce electricity or liquid fuel (biodiesel) for the feedstocks were identified. Transaction and $/kWh or $/gallon costs were developed for each conversion technology (see discussion for individual renewable technologies which follows in this document). Transaction costs were categorized as either investment, operating, depreciation, or byproduct. For each new conversion technology, total industry output, employment, employee compensation (wages, salaries, and benefits), and proprietary income (self-employed income) were projected. In addition, new production functions were developed and added to the model to represent the renewable energy sectors added to the IMPLAN model. Once the new sectors were created, based upon their production technologies and costs, and added into the model, economic impacts from providing the energy amounts shown in Table 1 were calculated. Each of the renewable technologies added into the model are discussed below. IX. High-profile Renewables Wind, sun, and water are the “poster children” for renewable energy generation. Collectively, however, they will only constitute 25 percent of the amount generated by TVA to meet its 2020 target. There are limitations on the amount that can or should be generated from each, for very different reasons, as discussed below. Despite their limitations, they can still legitimately be portrayed as the public “face” for renewables in the region.

• Incremental Hydropower Incremental hydropower is defined as “additional generating capacity achieved from increased efficiency or additions of new capacity at an existing hydroelectric facility.” While environmentalists are adamantly opposed to the construction of new hydropower facilities, there seems to be little objection to wringing more capacity from existing ones. This is usually

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accomplished through such measures as turbine replacement, the addition of new penstocks, and system or process optimization changes. TVA has had a Hydro Modernization Program (HMOD) in place since 1992, the purpose of which, in part, is to gain generating capacity and efficiency at its existing dams. The goal has been to gain an additional 750 MW of generating capacity through its extensive hydropower facilities. As of 2005, TVA had achieved approximately 400 MW of the goal and was on course to fully achieve the entire goal by 2015. This study assumes that the RPS encourages TVA to find another 50 MW of generating capacity beyond its current goal, such that, in total, another 400 MW of generating capacity is brought on-line from 2005 to 2016. TVA listed where efficiency improvements were to take place, post 2001, in its Reservoir Operations Study—Final Programmatic EIS.15 Seventeen power plants encompassing 49 units in all were identified, located in Tennessee, North Carolina, Georgia, and Alabama. As noted in Table 1, over 1.5 billion kWh would be produced through this program, constituting 8 percent of TVA’s renewable target. There has been virtually no controversy, or even discussion, of HMOD, and none is expected in the future. These changes can be delivered at low capital and operating costs, making them ideal sources of renewable power for meeting an RPS. The fact that TVA has undertaken the program absent the prodding of an RPS, or even inclusion within the Green Power Switch program, means that the effort is one that makes sense from purely a business perspective. While a small amount of low-head, or small scale, hydro could be obtained from streams in the TVA region, this study will not include any of this potential resource. Though the environmental impacts of low-head hydro come no where near matching those associated with dams, there are still issues—such as high sediment load and impact on aquatic life—that could occasion significant public opposition. For employment analysis, it is assumed that 17 dams or 49 turbines were chosen for modernization in the relevant time-period. Cost ranges included: a) turbine installation of $200 to $500 per MWh, b) automatic and control system costs of $60 to $120 per MWh, c) system optimization, plant/unit optimization, and process improvement costs of $5 to $50 per MWh, and d) operating costs of $1.30 to $1.35 MWh. Based on these parameters, to obtain an additional generation of 1.5 billion kWh, investment costs were estimated at $599.3 million with operating costs totaling $1.7 million annually. Approximately eight employees were estimated for operation and maintenance.16

• Wind Wind constitutes the most notable renewable energy success story to date, nationally. Decreasing capital and operating costs are leading to the installment of thousands of megawatts of generating capacity from wind across the United States. With over 9,000 MW of installed capacity, the United States currently ranks third among the community of nations, behind only Germany and Spain in installed capacity.

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Much of the generation is taking place in the West, and, as noted previously, the Southeast is considered a wind-poor region in general. The TVA region, however, contains significant wind energy potential, located either in the Cumberland or the Appalachian Mountains. A reasonable estimate of this potential ranges from 750 MW to 2,000 MW generating capacity, at wind speeds of Class 3 or higher. A study conducted in North Carolina has concluded that western North Carolina alone could be the site of 8,860 MW of generating capacity, obviously located on mountain summits or ridge crests.17 Much (but not all) of this capacity falls outside the TVA region, and there is currently a major policy roadblock to development of this resource in the form of the North Carolina Mountain Ridge Protection Act of 1983. This Act prohibits the construction of structures taller than 35 feet on North Carolina ridges above 3,000 feet in elevation. This study assumes that at some time in the 2006-2020 time frame, the Act is modified to allow the construction of windmills, thereby allowing utilities in North Carolina as well as TVA to tap into at least some of this large, renewable resource in the region. Since North Carolina would be covered by a federal RPS, it too would have an incentive in seeing the Mountain Ridge Act impediment removed. Currently, TVA has 29 MW of generating capacity on-line (atop 18 towers) at the Buffalo Mountain site in Anderson County, Tennessee, which is feeding into the Green Power Switch program. Prior to large-scale siting at this location, TVA sought to add capacity close to Chattanooga and in the North Carolina mountains. In both instances, it was met with public resistance, and the agency withdrew its initiatives. While environmentalists and the general public favor greater use of wind in principle, the huge 50-meter or higher towers and large turbines impair the “viewshed” according to many who would come in close contact with the machines. Many residents and tourists go to the mountains to savor nature and escape from towering man-made structures. Certainly, national and state parks should be declared off-limits to modern-day windmills. It is likely, therefore, that installed capacity will be considerably less than what might be technically feasible or desirable. We nonetheless still anticipate vigorous growth from the 29 MW capacity of today to 1,070 MW capacity in 2020. The costs for building and utilizing this capacity will be more than that associated with coal or uranium fired units but still affordable in terms of renewable energy sources. TVA has declared that it has already identified no fewer than 552 sites suitable for preliminary assessment in the region.18 With larger capacity turbines being the growing norm within the industry, fewer units will have to be installed in the future than has been the practice in previous years. We assume that approximately 580 MW is first installed in East Tennessee and Virginia along the Cumberland and Appalachian Mountains. Subsequent siting would take place in western North Carolina and northeastern Georgia. Wind is likely to have a capacity factor of 25 percent; hence, wind can provide over 2.3 billion kWh toward TVA’s renewable requirement (approximately 12 percent of the total) by 2020.

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A wind turbine power plant with variable speed and pitch horizontal axis was used to estimate engineering economic data for a representative wind technology. The system had approximately 10 units with each having a 1.5 MW capacity. Total nameplate rating capacity for the facility was 15 megawatts. Each representative facility required 15 employees.19 A total of 1,070 MW installed capacity was required for the region to generate over 2 billion kWh of electricity annually. Investment costs totaled $370.9 million with operating/depreciation costs totaling $32.7 million.20 The number of employees required to operate the facilities were 267.

• Solar Ideally, TVA would meet an RPS requirement entirely through the application of solar-electric technology, since it represents the most popular renewable resource in the region (according to polls). Unfortunately, and absent a radical breakthrough in solar technologies, the contribution of solar to the 2020 target will be marginal, at best. While the costs of solar photovoltaics have decreased for decades (falling from $1/kWh in 1980 to $.20/kWh today), they are still 2-3 times more expensive than other renewable technologies.21 Future-generation solar photovoltaics, based on thin film materials or organic nanotechnology components, may bring about the revolution we all seek, but they are unlikely to do so in the time frame of an initial federal RPS. We assume in this study that decentralized solar photovoltaics will be the only electricity-generating solar technology applied in this region. States such as California, Arizona, Nevada, and New Mexico have the opportunity to build large, centralized, solar-collecting plants (based on parabolic troughs, dish-Stirling engine systems, power towers, or concentrating photovoltaic systems), but the TVA region is lacking the amount of solar radiation necessary to make these technologies feasible here. Moreover, we assume that solar thermal, for heating and cooling, will not be counted toward an RPS target since, in most cases, it is displacing natural gas rather than conventionally generated electricity. Despite solar’s limitations, TVA can and should launch an aggressive photovoltaics initiative to demonstrate its commitment to renewable resource generation. TVA has already installed solar photovoltaic panels at 16 sites under the Green Power Switch program, constituting nearly 400 KW in generating capacity. An impressive, and feasible, demonstration would involve TVA increasing its commitment 20-fold, such that it would have 8 MW of generating capacity on-line by 2020. Assuming a capacity factor of 15 percent, this would mean generation of approximately 10 million kWh per year. This commitment does very little to help TVA achieve its quantitative target, but it could be a demonstrable and impressive undertaking consistent with the goals and purposes of the RPS. Solar conversion cost estimates were based on research by Singh and Fehrs in which an estimated 35.5 person-years labor requirement is needed per megawatt of photovoltaics.22 In this study, hours of labor were estimated by project activity and occupational category based on a survey of labor requirements for a 2 kW residential photovoltaic system. To provide a total of 8 MW of capacity or 10 million kWh generated annually, the estimated number of jobs by occupational category for the investment impacts included: a) professional, technical, and

21

management—82; b) clerical and sales—21; c) service—1; d) processing—31; e)machinery trades—14; f) benchwork—42; g) structural work—41; and h) miscellaneous—34. Matching the jobs to the investment cost ratio used by IMPLAN yielded an estimate of investment costs of $29.1 million used in the analysis. Using this same procedure, an estimated 20 jobs are required for operation and maintenance of the system, yielding an operating cost estimate of $1.8 million annually. X. Low-Profile Renewables Low-profile renewables are those dealing primarily (though not exclusively) with recovery of energy from waste. These processes are desirable because they transform waste into resources, but they do not have the same clean image possessed by wind or solar. They are not large sources of renewable energy for electricity, comprising collectively only 10 percent of the generated total, but they all make a contribution.

• Landfill Gas Several state-based RPS efforts count the conversion of municipal solid waste to energy toward their renewable energy goal, while federal RPS versions have, to date, disallowed this resource from counting as a renewable. This is a reflection of the mixed reputation solid-waste burning has amongst the environmental community. We assume in this study that this conversion will not be allowed in a future federal RPS. One activity associated with municipal solid waste that carries no such baggage is the capture of gas (primarily methane) from landfills constructed to sequester solid waste. Landfill gas is the natural by-product resulting from the decomposition of solid waste in landfills. The technology for the collection of methane is not high-tech, but consists of a series of wells that direct methane to a central point where it is processed and treated. The gas then is usually fed to an internal combustion (reciprocating) engine or turbine for the production of electricity. The environmental benefits arise from the avoidance of venting methane (a potent greenhouse gas) to the atmosphere and the substitution of this resource for more conventional electricity-generating resources. The U.S. government encourages this recovery through a landfill-gas tax credit and through the EPA Landfill Methane Outreach Program (LMOP), which is a voluntary, partnership program that promotes the use of landfill gas as a renewable energy source. As of the end of December 2005, LMOP reports that there are approximately 395 landfill gas projects underway in the United States and another 140 under construction or evaluation.23 LMOP has produced a landfill database of current and candidate landfill-gas projects. It shows 10 MW of generating capacity currently operating in the TVA region (and not captured by the

22

Green Power Switch program) and another 25 MW of capacity as good candidates. This study assumes that this entire total will be developed by 2020 and counted toward the RPS (a capacity factor of 85 percent is assigned to this resource). Approximately 261 million kWh would be produced annually, constituting a little over 1 percent of the renewable energy total. Landfill-gas recovery is a relatively inexpensive renewable energy option for TVA, so there should be no delay in exploiting available resources. TVA believes that there is considerably more landfill gas capacity available in the region, but it is assumed that this additional amount will be developed post-2020. Engineering economics for a representative landfill to methane conversion facility was based on a representative 4.6 MW capacity operation. The representative landfill has an average annual municipal solid-waste acceptance rate of 250 thousand tons. A total of 34.8 megawatts of capacity are required to produce 261 million kWh of electricity annually. Each representative facility requires five employees.24 Approximately 40 employees are estimated to operate the facilities. Investment costs and operating/depreciation costs totaled $51.4 and $11.2 million, respectively.25

• Wastewater Gas Just as with landfills, methane can be collected and burned at wastewater treatment plants across the United States.; only in this case, the gas must be produced rather than simply collected. This is accomplished by passing wastewater through an anaerobic digester where bacteria digest residual solids and create methane as a byproduct. The gas is then run through a microturbine or engine to produce electricity. The practice is still uncommon at wastewater facilities (only 2 percent of the 16,000 wastewater treatment plants in the United States employ this technology), but it is simple and conventional technology. TVA has been including the electricity produced from the Memphis wastewater treatment plant (4 MW capacity) in its Green Power Switch offering. This study assumes that a total of 16.25 MW of generating capacity can be developed over the TVA region by 2020. This capacity would be located at the large wastewater treatment plants in major urban areas. Applying an 85-percent capacity factor will generate roughly 120 million kWh, or nearly 0.5 percent of the required TVA renewable target. Wastewater methane-recovery cost estimates for a representative facility were based on two new 700 kW (1,400 kW annually) units retrofitted to the existing municipal solid-waste management system to provide a total of 121 million kWh of electricity annually. Each unit will require 12-13 jobs annually for a total of 25 employees.26 Byproduct or revenue generated from electricity savings totaled $2.1 million annually. Operating costs are estimated at $3.8 million with investment costs totaling $20.2 million.

23

• Animal Waste Animal waste can be put through digesters or incinerators to produce renewable electricity. Large quantities of waste material must be generated and be available locally for the technology to become economically viable. The growth of large, concentrated, feedlots over the past two decades makes this a distinct possibility. North Carolina has one of the largest feedlot concentrations (for pork), but it is located in a section of the state well outside the TVA region. The poultry industry has grown enormously and primarily in the South. Georgia is the largest poultry producing state in the nation, raising as many as 1.3 billion broilers per year; but, again, the poultry industry in Georgia is outside the TVA region. The large-scale poultry waste production in the TVA region occurs in Alabama and Mississippi. Alabama produces 1.1 billion broilers per year, and Mississippi, 828 million, much of this production concentrated in TVA counties. For this reason, we foresee the construction of two, 40 MW each, combustion facilities operating by 2020. One would be in Alabama and the other in Mississippi. An 80-percent capacity factor is assumed, producing 560 million kWh of electricity annually, or 3 percent of TVA’s renewable requirement. A combustion facility for poultry litter is already being built in Mississippi by FibroMiss, a division of the U.S. firm Fibrowatt, Ltd. As its feedstock, the facility will utilize primarily poultry litter but also combine it with forest residue. Animal-waste combustion has never been a particularly favored renewable option in the eyes of the environmental community. Air pollution concerns have surfaced at existing combustion facilities. Plus the extent to which energy generation encourages further concentration of feed animals will occasion major opposition. The concentrated animal feedlot operation (CAFO), in itself, raises great concern over land and water pollution, in addition to fear over the concentration of power within the industry. We could, therefore, see this option drop out in a future version of the federal RPS. Since it has been included in earlier versions, however, we will include it in this analysis. Since direct combustion of poultry litter is a little-used alternative with no engineering specifications publicly available, a direct wood-fired 25 MW plant was chosen as a representative technology to burn poultry litter generated by animal-waste facilities in the TVA region. A regional total of 80 megawatts of capacity is required to generate the 560,640 MWh shown in Table 1 (assuming an 80 percent-capacity factor). Investment costs for the facilities totaled $155.6 million with annual operating and depreciation costs totaling $20.5 million. For each plant, 20-30 employees are required. For this project, we are assuming 26 are needed for each plant—25 employees plus a plant manager.27 Therefore, for the entire animal-waste technology in the TVA region, approximately 67 employees would be required.

24

• Biodiesel Considerable investment is now taking place within the TVA region, throughout the Southeast, and, indeed, across the country related to biodiesel production facilities. The investment is, of course, targeted to developments in the transportation sector, but the opportunity to use biodiesel for the production of electricity has not been overlooked. TVA is currently a partner in the McMinnville BioDiesel Project, a collaborative effort to assess the performance characteristics of use of soy-based biodiesel in diesel-powered electricity generators. The objective of this demonstration project, carried out by the McMinnville (TN) Electrical System, is to assess how this system, equipped with state-of-the-art emissions controls, can perform both economically and environmentally (in limiting air pollutants). This study assumes that the results from this demonstration are positive and that a limited amount of biodiesel is utilized by utilities such as the McMinnville operation. A more substantial contribution can come from TVA’s utilization of biodiesel in its existing power-generating facilities. TVA has six combustion turbine plants and a fleet of diesel generators at its coal-fired plants. These units can burn either natural gas or liquid diesel fuel--depending on which is less expensive—and are used as peaking units. Annual generation from these plants, as one would expect, is small in comparison with that produced by baseload plants, and variable. In FY 2005, close to 600 million kWh of electricity was generated by the plants. For the purposes of this study, we assume that biodiesel displaces all of the natural gas and conventional diesel usage and that another 100 million kWh is generated through local utility systems, such as the McMinnville Electrical System. Hence, we assume a total of 700 million kWh generated from this renewable source in 2020, constituting roughly 3.5 percent of TVA’s renewable energy requirement. It may be possible to co-fire biodiesel or a bio-oil combination with coal in TVA’s coal-fired boilers. This can be accomplished by spraying either biodiesel or bio-oil onto the coal in the boiler. These options need to be explored but are not accounted for in the totals provided. Generating electricity from biodiesel requires that the feedstock be produced. In the analysis, it is assumed that feedstock is produced within the region though it might very well be imported. Engineering economic conversion cost information for the representative biodiesel facility was based on a 13-million gallon annual production biodiesel facility. The facility would process about 12.9 million gallons of soybean oil from 9 million bushels of soybeans. Investment costs totaled $251 million. A total of 87.5 million gallons of biodiesel would be required to generate 700,000 MWh in the region. Annual operating and depreciation costs totaled $364.5 million (approximately 77 percent is feedstock costs). Byproducts from the production process include credits for glycerin and soap stock plus federal incentive credits totaling $135.3 million. A total of 6.73 facilities would be required with each facility requiring 18 employees.28 Therefore, the number of employees estimated to operate the facility is 121.

25

XI. Work-Horse Renewables Biomass that is collected and co-fired with coal in TVA’s thermal plants is what we are calling “work-horse” renewables because they constitute the majority of what TVA will have to utilize to reach the RPS requirement. Fully 63 percent of the kilowatt hours generated by TVA to meet the RPS requirement would come from biomass co-firing with coal. The technology of co-fired biomass with coal is conventional and well understood. Approximately 100 electricity-generating plants across the country have burned mixtures of coal and biomass at some time.29 TVA experimented with co-firing in the 1990s at the Allen, Kingston, and Colbert power plants. Efforts to mainstream the experiments were never instigated since TVA determined that it was more costly to co-fire than simply burn coal. In terms of co-fire’s economics relative to other renewable options, however, the technology is quite favorable. In its 2005 Information Report, TVA states, “Co-firing is a near-term, low-cost option for efficiently and cleanly converting biomass to electricity by adding biomass as a partial substitute fuel in coal boilers.”30 It is important for TVA to maximize its investment in this low-cost option. For this reason, we assume that TVA will want to co-fire with 15 percent biomass (by weight) in all of its existing coal-fired boilers. This is toward the upper end of what is considered desirable. Some boilers are better able to accommodate this percentage than others, but co-firing with biomass can be accomplished in either the pulverized-coal units or the cyclone units that TVA operates (more work on preparing and handling the feedstock is required for pulverized coal units). TVA will have to launch a major, concentrated, effort to secure the massive amount of supplies required to accomplish this mission. Current supplies of biomass are either non-existent (energy crops) or subject to competitive prices. With the proper effort and commitment, however, TVA will be more demand-limited than supply-limited. Sufficient supplies can be obtained for $30/ton or less, within a circumference of 35 miles from a fossil-fuel plant (see the accompanying plant-by-plant breakout in Appendix A). But TVA must guarantee a market for these supplies. TVA burned over 45 million tons of coal in its 11 coal-fired plants in 2005. If we substitute 15 percent of that amount with biomass, we find that TVA will have to obtain nearly 6.8 million tons of biomass per year. TVA will also have to create a feeding and handling system at each facility to accommodate these new resources. Relatively little will have to be done at the Allen and Paradise facilities with cyclone boilers. The other units, however, will need to pulverize the material and use a direct or pneumatic injection system for delivering the material to the boilers. The capital costs for this preparatory work are not large relative to TVA’s enormous investments in these fossil fuel units, but again they do require full management and operational support. A major reason why the percentage of biomass is maintained at such a minimum level is because of its inferior heating value relative to coal. A pound of biomass delivers only 60 percent of the

26

BTU value derived from a pound of coal. Hence, an 85:15 mix would mean that TVA would be generating about 6 percent less energy from its fossil-fuel boilers than it would with a 100 percent use of coal. Still another concern worth noting is whether the alkali content in biomass will contaminate the Selective Catalytic Reduction (SCR) units being installed at several TVA power plants. Biomass can, of course, be utilized in stand-alone applications. The pulp and paper industry uses biomass in direct-fired boilers on a significant scale. Utility-size use, however, to generate electricity, is not proposed in this analysis as it would likely be expensive even in relative terms. Demonstrations of biomass gasification, in combined cycle applications, are taking place and hold out significant hopes for economical operation, but this technology has yet to be commercialized. For these reasons, we include only biomass co-firing in the RPS analysis.

• Residues TVA will be able to co-fire a significant amount of biomass in the form of residues coming from agriculture, forest, and mill products. TVA could expect to get such materials as sawdust, bark, and wood shavings from such places as sawmills, furniture mills, manufactured-home companies and flooring mills. Crop residues (stalks and leaves) would be available from the agriculture sector. Much of this material is already being used productively in the TVA region, so TVA would not have access to the entire universe of biomass residue. Nevertheless, according to our analysis, TVA would still have abundant resources to draw from and fulfill the 6.8-million-ton requirement set forth earlier. Agriculture residues would be used sparingly in co-firing, not only because they are the most limited residue available, but because their BTU value is the lowest of all the residues. We calculate that about 130 thousand tons of agriculture residues would be co-fired in a year, constituting less than 2 percent of the biomass burned in TVA boilers. This total would produce a little over 181 million kWh per year. Forest residue is more prized as a biomass fuel since its BTU value is 10 percent greater per unit than that of agricultural residues. It would make up about 11 percent of the biomass TVA would need and produce 1.1 billion kWh per year. All but 8 percent of the total could be obtained for $30/ton or less (not counting transportation costs). Mill residue, like forest residue, has a relatively high biomass BTU value. About 20 percent more mill residue can be obtained over forest residue quantities, all at $30 per ton or less (not counting transportation costs). Hence it would make up close to 14 percent of the biomass TVA would need and produce 1.3 billion kWh per year. Significant additional quantities of agricultural, forest, and mill residues could be obtained by TVA for $50/ton or less, but from energy and cost perspectives it makes sense to obtain energy crops to meet the required demand.

27

• Energy Crops The largest contribution to TVA’s efforts to meet an RPS requirement would come from the large-scale usage of energy crops, or more specifically, the co-fire of switchgrass in TVA’s fossil- fuel boilers. This study envisions TVA meeting 35 percent of its 2020 requirement by burning energy crops in TVA boilers. Switchgrass has been co-fired on an experimental basis in boilers owned by Alliant Energy (Iowa) and the Southern Company, but a full-scale commercial enterprise has yet to develop. There appears to be no technical barriers preventing such a development, however. Switchgrass is an ideal energy crop because it produces a high yield (6 to 9 tons per acre annually), only needs to be planted every decade or so, is drought resistant and flood tolerant, and requires relatively low levels of fertilizer and herbicide applications once established. It can be grown on marginal farmland, such as hay and pasture lands, and requires no special technologies for harvesting.31 Its BTU value is approximately 5 percent greater than for typical agriculture residues, but 5 percent less than that for mill and forest residues. As noted previously, farmers would have to be guaranteed a price and a market prior to large-scale planting and harvesting. The potential for large-scale operations exists, however, as almost 10 million tons of switchgrass can be grown in the TVA region at a farmgate price of $30 per ton or less. The positive features from growing and burning this energy crop are several: diminished air emissions of pollutants (particularly sulfur), reduced erosion on farmland, and a better habitat for animals. Perhaps most important would be the positive employment impacts in rural areas. In summary, at a co-fire rate of 15 percent, regional cellulosic material requirements would be 6.8 million tons to produce 9.6 billion kWh of electricity annually. Employment impacts were estimated for biomass production, conversion, and transportation. Based on research from Singh and Fehrs,32 supplying 6.8 million tons of biomass requires 1,233 employees to produce the biomass feedstocks and 371 to transport the biomass. Approximately $277 million dollars in investment costs were estimated for biomass conversion. Operating and depreciation costs totaled $216 million with feedstock costs totaling 84.4 percent of that value33 Biomass conversion through co-firing will result in 77 direct employees based on seven additional employees per plant.34

28

GeorgiaAlabama

Kentucky

Tennessee

Mississippi

Illinois

Missouri

Indiana

South Carolina

North CarolinaArkansas

Ohio

Virginia

West Virginia

Louisiana

ALLEN

SHAWNEE

COLBERT

PARADISE

BULL RUNKINGSTON

GALLATINCUMBERLAND JOHN SEVIER

WIDOWS CREEK

JOHNSONVILLE

Figure 6. Buffer Rings to Determine Available Biomass for TVA’s Fossil Power Plants.

XII. Employment Results The results from the analysis are presented in Tables 2 through 5. For the annual operating impacts, biomass production had the largest direct employment impact, followed by biomass transportation, wind, and biodiesel (Table 2). Solar and hydro renewable technologies had the smallest. The total direct employment impacts are estimated at 2,229 jobs. For annual operating, the total employment impacts--including direct, indirect, and induced impacts--were largest from biodiesel, followed by biomass conversion, biomass production, wind, and biomass transportation. Estimated total employment impacts for annual operations are 16,291 jobs. The employment multipliers for annual operating impacts are displayed in the right-hand column of Table 2. For the annual operating impacts, the largest employment multiplier is for biomass conversion, followed by biodiesel, wind, and animal waste. Overall, for each job added from annual operating activities associated with providing renewable energy, an additional 6.31 jobs are projected to be created in the TVA region,

29

Table 2. Estimated Number of Jobs and Employment Multipliers for Annual Operating Impacts Employment (Jobs) Multiplier Renewable Energy Technology Direct Total Animal Waste 67 376 5.61 Biodiesel* 121* 5,707 47.17 Co-fire (Production of Biomass) 1,233 3,667 2.97 Co-fire (Transportation of Biomass) 371 868 2.34 Co-fire (Conversion of Biomass) 77 3,721 48.32 Incremental Hydro 8 22 2.75 Landfill Gas 40 218 5.45 Solar 20 36 1.80 Wastewater 25 140 5.60 Wind 267 1,536 5.75

Total 2,229 16,291 7.31 *If biodiesel were imported into the region these impacts would be significantly reduced. Shown in Table 3, the employment impacts from investment (manufacturing, construction, and installation) in renewable energy facilities are projected at 13,253 jobs direct and 28,372 jobs in total (including direct, indirect, and induced). For both direct and total employee impacts, biomass conversion produces the largest number of jobs, followed by wind, hydro, and biodiesel. The largest employment multiplier from investment in renewable energy facilities are for hydro followed by biodiesel, solar and/or animal waste, and wind. Overall, for each job added from investment in renewable energy facilities, an additional 1.14 jobs are projected to be created in the TVA region.

The projected total number of jobs (direct, indirect, and induced) created from each type of renewable energy (Tables 2 and 3) are summed across operating and investment in Table 4, below. A total of 44,663 jobs are projected as being created in the TVA region as a result of a

Table 3. Estimated Number of Jobs and Employment Multipliers for Investment Impacts. Employment (Jobs) Multiplier Renewable Energy Technology Direct Total Animal Waste 1,287 2,712 2.11 Biodiesel 1,824 4,029 2.21 Co-fire (Biomass Conversion) 3,763 6,863 1.82 Incremental Hydro 2,072 6,034 2.91 Landfill Gas 473 948 2.00 Solar 266 561 2.11 Wastewater 386 651 1.69 Wind 3,182 6,574 2.07

Total 13,253 28,372 2.14

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federal RPS pegged at 10 percent by 2020. The largest number of these jobs is created through the utilization of biofuels (biodiesel and cellulosic biomass). Indeed, biodiesel and cellulosic biomass constitute 85 percent of all the operating jobs on an annual basis. Though a systematic study of where these jobs would be created has not been attempted, it appears that most would be created in rural areas, precisely where jobs are needed the most.

Still another way of portraying employment impacts is to estimate the number of jobs per unit of energy produced from each type of renewable technology. The estimated number of jobs per 1,000 MWh of energy produced from each of the renewable sources is shown in Table 5. When calculated on this basis, for operating impacts, biodiesel has the largest number of job impacts, followed by solar and wastewater. For investment, solar has the largest employment impacts followed by biodiesel and wastewater. Table 5. Estimated Number of Jobs per 1000 MWh. Total Jobs per 1,000 MWh Renewable Energy Technology Operating Investment Animal Waste 0.67 4.84 Biodiesel 8.15 5.76 Co-fire of Cellulosic Materials 0.85 0.71 Incremental Hydro 0.01 3.85 Landfill Gas 0.83 3.63 Solar 3.42 53.37 Wastewater 1.16 5.38 Wind 0.66 2.81

Total 1.09 1.86

Table 4. Total Estimated Number of Jobs Employment (Jobs) Total Renewable Energy Technology Operating Investment Animal Waste 376 2,712 3,088 Biodiesel 5,707 4,029 9,736 Co-fire (Biomass) 8,256 6,863 15,119 Incremental Hydro 22 6,034 6,056 Landfill Gas 218 948 1,166 Solar 36 561 597 Wastewater 140 651 791 Wind 1,536 6,574 8,110

Total 16,291 28,372 44,663

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IVX. Employment Summary and Discussion Using the IMPLAN input-output model, we have seen that TVA can create thousands of new jobs by diligently fulfilling the mandates of a federal RPS. The connection between renewables and jobs is not a new one. Numerous states have already studied this relationship.35 And, it is sometimes stated that Germany’s aggressive push for renewable technologies is not so much an environment/energy program as it is a jobs program36 It must be acknowledged, however, that if the increasing demand for TVA electricity were not met, in part, by the renewables highlighted in this study, it would be met by conventional energy sources. And these technologies would have job consequences as well. As such, it is necessary to consider the employment consequences of meeting the 15.2 billion kWh output (Table 1) not through renewables, but through conventional sources, such as coal. If the energy produced by renewables were produced by coal instead, TVA would have to construct two very large power plants (approximately 1,000 MWe each). Singh and Fehrs have shown that the jobs directly created through coal production are not as large in number as those created from renewables.37 As illustrated in Table 5, we calculated that the renewables generated in this study would produce 2.95 jobs/1,000 MWh of generation. Singh and Fehrs calculate that coal’s jobs impact is only 1.01 jobs for a comparable unit of delivered energy. This differential in job creation was confirmed in the report by Kammen, et al, that looked at job creation numbers across 13 independent reports and studies of renewable energy and employment.38 Hence the employment derived from TVA’s construction and operation of two new power plants would not match that derived from the dispersed renewables set forth in this study. Not all of the employment impacts in the TVA region emanating from a federal RPS are captured within the IMPLAN framework. A federal RPS will catalyze renewable energy use throughout the country, and TVA-region manufacturing enterprises would undoubtedly be a beneficiary in terms of employment gains associated with equipment that would be installed and used nationally. Manufacturing firms in wind and solar energy technologies are particularly relevant. Tennessee already hosts two major manufacturing industries in the renewable area. Sharp Manufacturing Corporation in Memphis manufactures solar photovoltaic modules, and Aerisyn in Chattanooga constructs wind towers. The markets for these products are national and global. Sharp’s plant in Memphis is already the largest photovoltaic manufacturing facility in the United States and currently employs 200. An estimated additional 200 jobs are derived from this employment indirectly. Aerisyn currently employs 163 with another 148 jobs created indirectly. An attempt by the Renewable Energy Policy Project (REPP) has been made to identify locational employment impacts associated with greater utilization of solar and wind technologies nationally. Their projections are based on identifying currently operating manufacturing firms (through their NAICS codes) that could expand if demand surged.

32

Table 6 provides a breakout of employment impacts for those states within the TVA region associated with a rise in national demand for solar of 9,600 MWe and of wind for 50,000 MWe. Total direct jobs for solar within the seven-state grouping comes to 3,398. The employment impacts of the projected growth in wind technology are even more impressive, totaling 23,203 new jobs covering the seven states. Of course, not all of the employment in these seven states, other than Tennessee, would fall within the TVA region. Table 6. Estimated Number of Jobs from Growth of Solar and Wind Technologies TVA Region States Solar Wind_______________________ North Carolina 1,078 4,661 Virginia 649 3,386 Georgia 504 3,532 Tennessee 375 4,233 Alabama 331 3,571 Kentucky 274 2,483 Mississippi 187 1,337 Total 3,398 23,203 _______________________________________________________________________ Source: Renewable Energy Policy Project, Wind Turbine Development: Location of Manufacturing Activity, September 2004; Renewable Energy Policy Project, Solar PV Development: Location of Economic Activity, January 2005. Clearly, the REPP analysis is not fine-grained enough to provide reliable quantitative estimates of manufacturing employment gains within the TVA region associated with increasing renewable energy production nationwide. It is illustrative, nonetheless, of the benefits that would accrue to the region from such a development.

33

34

APPENDIX A: Location of Counties for Renewable Energy Production

35

Scott

Marshall

Animal Waste

Figure A.1. Location of counties for animal waste conversion to electricity.

Jackson

Shelby

Kemper

Colbert

Marshall

Stewart

Warren

Sumner

Lauderdale

Roane

Hawkins

Haywood

Humphreys

Muhlenberg

Anderson

McCracken

Biodiesel

Figure A.2. Location of counties where biodiesel is converted to electricity.

36

Polk

Lauderdale

Sullivan

Hamilton

Rhea

Carter

Fannin

Cherokee

AndersonGrainger

Loudon

Washington

Incremental Hydro

Figure A.3. Location of counties where incremental hydro investments

occur.

37

Shelby

Knox

Obion

Logan

Blount

MorganMarshall

Lauderdale

Walker

Williamson

Christian

Cherokee

Benton

Hawkins

Limestone

Rutherford

Davidson

Pontotoc

Chickasaw

Montgomery

Bradley

Marshall

Jefferson

Whitfield

Washington

Landfill Gas

Figure A.4. Location of counties where landfill gas conversion investments

occur.

38

Shelby

Knox

Madison

Sevier

Tate

Fayette

Blount

Marshall

Morgan

Marion

Desoto Lauderdale

Sullivan

Williamson

Sumner

Hamilton

Madison

Hardeman

Carter

Haywood

Rutherford

Davidson

Washington

Avery

Bradley

Meigs

AndersonWataugaWashington

Solar

Figure A.5. Location of counties where solar residential units investments occur.

Shelby

Knox

Walker

Sullivan

Christian

Hamilton

Davidson

Chickasaw

Wastewater

39

Figure A.6. Location of counties where wastewater conversion investments occur.

Lee Scott

Scott

Walker

Clay

Morgan

Rhea

Roane

Carter

UnionMurray

Washington

Avery

Johnson

Watauga

Wind

Figure A.7. Location of counties where wind turbine investments occur.

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APPENDIX B: Renewable Energy Credits (RECs) RECs are the environmental attributes or benefits associated with renewable electricity generation, and when exchanged separately from electricity generation, they are called “green tags” or “unbundled” RECs. They are a new economic commodity, gaining significant economic value as many utilities or independent generators are now recognizing that they can achieve their state-based RPS requirements only through the purchase of RECs. Significant economic penalties are prescribed for those who fall short of the quantitative targets. Those states that include energy efficiency in their RPS systems can also obtain “white tags;” i.e. RECs that are tied to measured energy efficiency savings taking place outside the RPS boundaries. Sterling Planet, a retailer of RECs, has recently announced its offering of these products. The creation of RECs is a market-based approach to promoting cost-effective flexibility in pursuit of regulatory goals. The structure assumes that consumers are indifferent as to where renewable energy generation takes place in the United States, and that least-cost strategies constitute the most highly valued method for achieving goals. It also assumes, with considerable justification, that some generators of RECs will be able to do so cheaply and sell surplus quantities to customers (such as TVA) who would find it costly to meet all of its renewable requirements through its own production. The costs of RECs in a federal RPS program are uncertain, but may range from $5 to $15 per MWh. Everyone agrees that for a REC system to be orderly and effective, an elaborate tracking system must be created detailing the type of fuel used to create the REC, where it took place, and when. The system needs to be clear with respect to ownership, transferability, and certification or verification. An institutional structure of marketers, brokers, certifiers, and verifiers needs to be put in place. Tracking programs currently exist in Texas, New England, and Wisconsin and are providing real-world experience in the challenges facing the institutionalization of RECs. Numerous groups are meeting on a regular basis to characterize what would constitute a desirable and workable tracking system across regions and, ultimately, within the nation as a whole. Such preparations are essential if an adequate system is to be in place with passage of a federal RPS.

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1 Energy Information Administration, Department of Energy, Annual Energy Outlook 2006, 2006. p. 15. 2 Barry G. Rabe, Race to the Top: The Expanding Role of U.S. State Renewable Portfolio Standards (prepared for the Pew Center on Global Climate Change), June 2006, Executive Summary. 3 Global Energy Decisions, Renewable Energy: The Bottom Line, 2005, p.1; Barry G. Rabe, “Renewable Energy,” June 15, 2006 address at the Pew Center on Global Climate Change, Arlington, VA. 4 Jeff Deyette and Steve Clemmer, “Closing the US Renewable Energy Gap,” Renewable Energy World, January-February, 2004, p. 40. 5 H.R. 6 Energy Policy Act of 2003; Section 606 of the Energy Policy Act of 2002; Section 609 of H.R. 6, 2005. 6 TVA, Energy Vision 2020, (Integrated Resource Plan/Environmental Impact Statement), vol. 1, 1995, p. 62. 7 EnergyBiz Magazine, May/June 2006, p. 74. 8 Gunnar Birgisson and Erik Petersen, “Renewable Energy Development Incentives: Strengths, Weaknesses and the Interplay,” The Electricity Journal, April 2006, p. 49. 9 Energy Efficiency and Renewable Energy, Department of Energy, “State Energy Alternatives: Tennessee Bioenergy Resources”, 2006. 10 TVA, “The Role of Renewable Energy in Reducing Greenhouse Gas Buildup” (www.tva.gov/environment/air/ontheair/renewable.htm) 11 Kim Jensen, et. al, “An Analysis of the Residential Preferences for Green Power—The Role of Bioenergy,” a paper presented at the Farm Foundation Conference on Agriculture as a Producer and Consumer of Energy, June 24-25, 2004. 12I-O models provide the most complete picture of employment gains, in contrast to “analytical models” that typically calculate only direct employment impacts. 13 Minnesota IMPLAN Group, IMPLAN System (www.implan.com), 2001; D. Olson and S. Lindall, “IMPLAN Professional Software, Analysis, and Data Guide,” Minnesota IMPLAN Group (www.implan.com), 1999. 14 Olson and Lindall. 15 TVA, Reservoir Operations Study—Final Programmatic EIS, 2003, Appendix A, Table A-09. 16 P. March, “Opportunities for Incremental Hydropower,” Renewable Energy Modeling Workshop on Hydroelectric Power (www.epa.gov/cleanenergy/pdf/march_may 10.pdf), 2005. 17 North Carolina State Energy Office, North Carolina State Energy Plan, June 2003, chapter 6 18 Rick Carson, “Lessons Learned at the TVA Wind Site,” presentation made at the Conference on Wind Powering in the Southeast, Knoxville, TN, June 28, 2001. 19 V. Singh and J. Fehrs, “The Work that Goes Into Renewable Energy,” Research Report for the Renewable Energy Policy Project (www.crest.org/articles/static/1/binaries/LABOR_FINAL_REV.pdf), 2001.

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20 EPRI, Renewable Energy Technical Assessment Guide—TAG-RE, 2004. 21 National Renewable Energy Laboratory, Renewable Energy Cost Trends, a publication of the Energy Analysis Office, 2004. 22 Singh and Fehrs 23 U.S. Environmental Protection Agency, “Landfill Methane Outreach Program” (www.epa.gov/lmop/proj/index.htm), 2005. 24 R. Yazdani, et.al “A Beneficial Investment in Trash,” Controlled Landfill Bioreactor Project, Urban Consortium Energy Task Force, Yolo County Planning & Public Works Department and Environmental Management (www.yolocounty.org/recycle/docs/UCETFreport.pdf), 2000. 25 U.S. Environmental Protection Agency, 2005. 26 R. Yazdani, et.al, 2000. 27 EPRI, Renewable Energy Technical Assessment Guide. 28 Burton English, et.al, Economic Feasibility of Producing Biodiesel in Tennessee, (http://web.utk.edu/`aimag/pubmkt.html), 2002. 29 Federal Energy Management Program, “Biomass Co-Firing in Coal-Fired Boilers” (DOE/EE-0288), 2005, p.4. 30 TVA, 2005 Information Statement, p.11. 31 David Bransby, “Switchgrass Profile,” (http://bioenergy.ornl.gov/papers/misc/switchgrass-profile.html) 32 Singh and Fehrs 33 Burton English, et.al., Economic Impacts of Using Alternative Feedstocks in Coal-Fired Plants in Southeastern United States, (http://web.utk.edu/aimag/pubimpact.html), 2004 34 B. Zemo, Telephone Conversation, Plant Manager, Alabama Power, May, 2005. 35 Center for Energy, Economic & Environmental Policy, Rutgers University, Economic Impact Analysis of New Jersey’s Proposed 20% Renewable Portfolio Standard, December 8, 2004; PennEnvironment Research and Policy Center, Renewables Work: Job Growth from Renewable Energy Development in the Mid-Atlantic, Spring 2004; Black & Veatch, Economic Impact of Renewable Energy in Pennsylvania, March 2004. 36 Referat Westliche Industreilander, Focus on Germany: Solar Energy in Germany, March 2006. 37 Singh and Fehrs 38 D. Kammen, et.al, Putting Renewables to Work: How Many Jobs Can the Clean Energy Industry Generate? (a report of the Renewable and Appropriate Energy Laboratory, Energy and Resources Group of the Goldman School of Public Policy, University of California, Berkeley), April 13, 2004.