ML053620060

Draft SEIS---Chapter 8 Website Documentation

ML053620060
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Site:	Brunswick
Issue date:	12/16/2005
From:	Carolina Power & Light Co
To:	Office of Nuclear Reactor Regulation
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!"rAlex Gabbard at the coal pile MOO for ORNL's steam plant Over the past few decades, the American public has become increasingly wary of nuclear power because of concern about radiation releases from normal plant operations, plant accidents, and nuclear waste. Except for Chemobyl and other nuclear accidents, releases have been found to be almost undetectable in comparison with natural background radiation. Another concern has been the cost of producing electricity at nuclear plants. It has increased largely for two reasons: compliance with stringent government regulations that restrict releases of radioactive substances from nuclear facilities into the environment and construction delays as a result of public opposition.

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e.4osed Jo rrA*d,?4Ofi dose'shan tfaose' kiig near n;/dw rpgouerfal6nts t6at meet goi ernme t regd ao, is Partly because of these concerns about radioactivity and the cost of containing it, the American public and electric utilities have preferred coal combustion as a power source. Today 52% of the capacity for generating electricity in the United States is fueled by coal, compared with 14.8% for nuclear energy.

Although there are economic justifications for this preference, it is surprising for two reasons. First, coal combustion produces carbon dioxide and other greenhouse gases that are suspected.to cause climatic warming, and it is a source of sulfur oxides and nitrogen oxides, which are harmful to human health and may be largely responsible for acid rain. Second, although not as well known, releases from coal combustion contain naturally occurring radioactive materials--mainly, uranium and thorium.

Former ORNL researchers J. P. Mc ride, R. E. Moore, J. P. Witherspoon, and R. E. Blanco made this point in their article "Radiological Ipact of Airborne Effluents of Coal and Nuclear Plants" in the December 8, 1978, issue of Scienc magazine. They concluded that Americans living near coal-fired power plants are exposed to higher adiation doses than those living near nuclear power plants that meet government regulations. Thi situation remains true today and is addressed in this article.

The fact that coal-fired power plants throughout the world are the major sources of radioactive materials released to the environment has several implications. It suggests that coal combustion is more hazardous to health than nuclear power and that it adds to the background radiation burden even more than does nuclear power. It also suggests that if radiation emissions from coal plants were regulated, their capital and operating costs would increase, making coal-fired power less economically competitive.

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'Coal Combustion Page 2 of 10 Finally, radioactive elements released in coal ash and exhaust produced by coal combustion contain fissionable fuels and much larger quantities of fertile materials that can be bred into fuels by absorption of neutrons, including those generated in the air by bombardment of oxygen, nitrogen, and other nuclei with cosmic rays; such fissionable and fertile materials can be recovered from coal ash using known technologies. These nuclear materials have growing value to private concerns and governments that may want to market them for fueling nuclear power plants. However, they are also available to those interested in accumulating material for nuclear weapons. A solution to this potential problem may be to encourage electric utilities to process coal ash and use new trapping technologies on coal combustion exhaust to isolate and collect valuable metals, such as iron and aluminum, and available nuclear fuels.

Makeup of Coal and Ash Coal is one of the most impure of fuels. Its impurities range from trace quantities of many metals, including uranium and thorium, to much larger quantities of aluminum and iron to still larger quantities of impurities such as sulfur. Products of coal combustion include the oxides of carbon, nitrogen, and sulfur; carcinogenic and mutagenic substances; and recoverable minerals of commercial value, including nuclear fuels naturally occurring in coal.

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~za/*isatoat25 &nes geater than the amoL~aarfitfrwJn Coal ash is composed primarily of oxides of silicon, aluminum, iron, calcium, magnesium, titanium, sodium, potassium, arsenic, mercury, and sulfur plus small quantities of uranium and thorium. Fly ash is primarily composed of non-combustible silicon compounds (glass) melted during combustion. Tiny glass spheres form the bulk of the fly ash.

Since the 1960s particulate precipitators have been used by U.S. coal-fired power plants to retain significant amounts of fly ash rather than letting it escape to the atmosphere. When functioning properly, these precipitators are approximately 99.5% efficient. Utilities also collect furnace ash, cinders, and slag, which are kept in cinder piles or deposited in ash ponds on coal-plant sites along with the captured fly ash.

Trace quantities of uranium in coal range from less than 1 part per million (ppm) in some samples to around 10 ppm in others. Generally, the amount of thorium contained in coal is about 2.5 times greater than the amount of uranium. For a large number of coal samples, according to Environmental Protection Agency figures released in 1984, average values of uranium and thorium content have been determined to be 1.3 ppm and 3.2 ppm, respectively. Using these values along with reported consumption and projected consumption of coal by utilities provides a means of calculating the amounts of potentially recoverable breedable and fissionable elements (see sidebar). The concentration of fissionable uranium-235 (the current fuel for nuclear power plants) has been established to be 0.71% of uranium content.

Uranium and Thorium in Coal and Coal Ash As population increases worldwide, coal combustion continues to be the dominant fuel source for electricity. Fossil fuels' share has decreased from 76.5% in 1970 to 66.3% in 1990, while nuclear energy's share in the worldwide electricity pie has climbed from 1.6% in 1970 to 17.4% in 1990.

Although U.S. population growth is slower than worldwide growth, per capita consumption of energy in this country is among the world's highest. To meet the growing demand for electricity, the U.S. utility industry has continually expanded generating capacity. Thirty years ago, nuclear-power appeared to be a

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Coal Combustion Page 3 of 1 0 viable replacement for fossil power, but today it represents less than 15% of U.S. generating capacity.

However, as a result of low public support during recent decades and a reduction in the rate of expected power demand, no increase in nuclear power generation is expected in the foreseeable future. As current nuclear power plants age, many plants may be retired during the first quarter of the 21st century, although some may have their operation extended through license renewal. As a result, many nuclear plants are likely to be replaced with coal-fired plants unless it is considered feasible to replace them with fuel sources such as natural gas and solar energy.

U.S. AND WORLD COAL COMBUSTION (mllions of kms)

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U.S. and world combustion of coal (in mdlions of metc om) has increased steadly from 1937to the pesenL It Is expected to increase even more between now and beyond 2040.

As the world's population increases, the demands for all resources, particularly fuel for electricity, is expected to increase. To meet the demand for electric power, the world population is expected to rely increasingly on combustion of fossil fuels, primarily coal. The world has about 1500 years of known coal resources at the current use rate. The graph above shows the growth in U.S. and world coal combustion for the 50 years preceding 1988, along with projections beyond the year 2040. Using the concentration of uranium and thorium indicated above, the graph below illustrates the historical release quantities of these elements and the releases that can be expected during the first half of the next century, given the predicted growth trends. Using these data, both U.S. and worldwide fissionable uranium-235 and fertile nuclear material releases from coal combustion can be calculated.

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Coal Combustion Page 4 of 10 ULS. AMD WVOMW RMLEASM OF URANMM AND THOBIUM I

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Ii 1*m M5c US. and world release of uraiuwn and ihorum (In metric tons) from coat combustion has risen steadily since 1937.

It Is projectd to continue to Increase though 2040 and beyond.

Because existing coal-fired power plants vary in size and electrical output, to calculate the annual coal consumption of these facilities, assume that the typical plant has an electrical output of 1000 megawatts.

Existing coal-fired plants of this capacity annually bum about 4 million tons of coal each year. Further, considering that in 1982 about 616 million short tons (2000 pounds per ton) of coal was burned in the United States (from 833 million short tons mined, or 74%/o), the number of typical coal-fired plants necessary to consume this quantity of coal is 154.

Using these data, the releases of radioactive materials per typical plant can be calculated for any year.

For the year 1982, assuming coal contains uranium and thorium concentrations of 1.3 ppm and 3.2 ppm, respectively, each typical plant released 5.2 tons of uranium (containing 74 pounds of uranium-235) and 12.8 tons of thorium that year. Total U.S. releases in 1982 (from 154 typical plants) amounted to 801 tons of uranium (containing 11,371 pounds of uranium-235) and 1971 tons of thorium. These figures account for only 74% of releases from combustion of coal from all sources. Releases in 1982 from worldwide combustion of 2800 million tons of coal totaled 3640 tons of uranium (containing 51,700 pounds of uranium-235) and 8960 tons of thorium.

Based on the predicted combustion of 2516 million tons of coal in the United States and 12,580 million tons worldwide during the year 2040, cumulative releases for the 100 years of coal combustion following 1937 are predicted to be:

U.S. release (from combustion of 111, 716 million tons):

Uranium: 145,230 tons (containing 1031 tons of uranium-235)

Thorium: 357,491 tons Worldwide release (from combustion of 637,409 million tons):

Uranium: 828,632 tons (containing 5883 tons of uranium-235) 1-...

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Coal Combustion Page 5 of 10 Thorium: 2,039,709 tons Radioactivity from Coal Combustion The main sources of radiation released from coal combustion include not only uranium and thorium but also daughter products produced by the decay of these isotopes, such as radium, radon, polonium, bismuth, and lead. Although not a decay product, naturally occurring radioactive potassium-40 is also a significant contributor.

Me,-pOpiaL&/ e/?eiCfir dos, ffglb/el7lt Arom zal/plants&s /00 bmes #bAS /hnm tznd&erp/antS According to the National Council on Radiation Protection and Measurements (NCRP), the average radioactivity per short ton of coal is 17,100 millicuries/4,000,000 tons, or 0.00427 millicuries/ton. This figure can be used to calculate the average expected radioactivity release from coal combustion. For 1982 the total release of radioactivity from 154 typical coal plants in the United States was, therefore, 2,630,230 millicuries.

Thus, by combining U.S. coal combustion from 1937 (440 million tons) through 1987 (661 million tons) with an estimated total in the year 2040 (2516 million tons), the total expected U.S. radioactivity release to the environment by 2040 can be determined. That total comes from the expected combustion of 111,716 million tons of coal with the release of 477,027,320 millicuries in the United States. Global releases of radioactivity from the predicted combustion of 637,409 million tons of coal would be 2,721,736,430 millicuries.

For comparison, according to NCRP Reports No. 92 and No. 95, population exposure from operation of 1000-MWe nuclear and coal-fired power plants amounts to 490 person-rem/year for coal plants and 4.8 person-rem/year for nuclear plants. Thus, the population effective dose equivalent from coal plants is 100 times that from nuclear plants. For the complete nuclear fuel cycle, from mining to reactor operation to waste disposal, the radiation dose is cited as 136 person-rem/year; the equivalent dose for coal use, from mining to power plant operation to waste disposal, is not listed in this report and is probably unknown.

During combustion, the volume of coal is reduced by over 85%, which increases the concentration of the metals originally in the coal. Although significant quantities of ash are retained by precipitators, heavy metals such as uranium tend to concentrate on the tiny glass spheres that make up the bulk of fly ash.

This uranium is. released to the atmosphere with the escaping fly ash, at about 1.0% of the original amount, according to NCRP data. The retained ash is enriched in uranium several times over the original uranium concentration in the coal because the uranium, and thorium, content is not decreased as the volume of coal is reduced.

All studies of potential health hazards associated with the release of radioactive elements from coal combustion conclude that the perturbation of natural background dose levels is almost negligible.

However, because the half-lives of radioactive potassium-40, uranium, and thorium are practically infinite in terms of human lifetimes, the accumulation of these species in the biosphere is directly proportional to the length of time that a quantity of coal is burned.

Although trace quantities of radioactive heavy metals are not nearly as likely to produce adverse health effects as the vast array of chemical by-products from coal combustion, the accumulated quantities of aD4.

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Coal Combustion Page 6 of 10 these isotopes -over 150 or 250 years could pose a significant future ecological burden and potentially produce adverse health effects, especially if they are locally accumulated. Because coal is predicted to be the primary energy source for electric power production in the foreseeable future, the potential impact of long-term accumulation of by-products in the biosphere should be considered.

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£Ze c&~/%5Wzsed Energy Content: Coal vs Nuclear An average value for the thermal energy of coal is approximately 6150 kilowatt-hours(kWh)/ton. Thus, the expected cumulative thermal energy release from U.S. coal combustion over this period totals about 6.87 x 10E14 kilowatt-hours. The thermal energy released in nuclear fission produces about 2 x lOE9 kWh/ton. Consequently, the thermal energy from fission of uranium-235 released in coal combustion amounts to 2.1 x 10E12 kWh. If uranium-238 is bred to plutonium-239, using these data and assuming a "use factor" of 10%, the thermal energy from fission of this isotope alone constitutes about 2.9 x IOE14 kWh, or about half the anticipated energy of all the utility coal burned in this country through the year 2040. If the thorium-232 is bred to uranium-233 and fissioned with a similar "use factor", the thermal energy capacity of this isotope is approximately 7.2 x 10E14 kWh, or 105% of the thermal energy released from U.S. coal combustion for a century. Assuming 10% usage, the total of the thermal energy capacities from each of these three fissionable isotopes is about 10.1 x lOE14 kWh, 1.5 times more than the total from coal. World combustion of coal has the same ratio, similarly indicating that coal combustion wastes more energy than it produces.

Views of the TennesseeValleyAuthoritys Bull Run and Kingston Steam Plants. These coal-fired facilities generate electricity for Oak Ridge and the surrounding area.

Consequently, the energy content of nuclear fuel released in coal combustion is more than that of the coal consumed! Clearly, coal-fired power plants are not only generating electricity but are also releasing nuclear fuels whose commercial value for electricity production by nuclear power plants is over $7 trillion, more than the U.S. national debt. This figure is based on current nuclear utility fuel costs of 7 mils per kWh, which is about half the cost for coal. Consequently, significant quantities of nuclear materials are being treated as coal waste, which might become the cleanup nightmare of the future, and their value is hardly recognized at all.

How does the amount of nuclear material released by coal combustion compare to the amount consumed as fuel by the U.S. nuclear power industry? According to 1982 figures, 111 American nuclear plants consumed about 540 tons of nuclear fuel, generating almost 1.1 x IOE12 kWh of electricity. During the same year, about 801 tons of uranium alone were released from American coal-fired plants. Add 1971 tons of thorium, and the release of nuclear components from coal combustion far exceeds the entire U.S.

consumption of nuclear fuels. The same conclusion applies for worldwide nuclear fuel and coal I

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Coal Combustion Page 7 of 1 combustion.

Another unrecognized problem is the gradual production of plutonium-239 through the exposure of uranium-238 in coal waste to neutrons from the air. These neutrons are produced primarily by bombardment of oxygen and nitrogen nuclei in the atmosphere by cosmic rays and from spontaneous fission of natural isotopes in soil. Because plutonium-239 is reportedly toxic in minute quantities, this process, however slow, is potentially worrisome. The radiotoxicity of plutonium-239 is 3.4 x lOEl 1 times that of uranium-238. Consequently, for 801 tons of uranium released in 1982, only 2.2 milligrams of plutonium-239 bred by natural processes, if those processes exist, is necessary to double the radiotoxicity estimated to be released into the biosphere that year. Only 0.075 times that amount in plutonium-240 doubles the radiotoxicity. Natural processes to produce both plutonium-239 and plutonium-240 appear to exist.

Conclusions For the 100 years following 1937, U.S. and world use of coal as a heat source for electric power generation will result in the distribution of a variety of radioactive elements into the environment. This prospect raises several questions about the risks and benefits of coal combustion, the leading source of electricity production.

First, the potential health effects of released naturally occurring radioactive elements are a long-term issue that has not been fully addressed. Even with improved efficiency in retaining stack emissions, the removal of coal from its shielding overburden in the earth and subsequent combustion releases large quantities of radioactive materials to the surface of the earth. The emissions by coal-fired power plants of greenhouse gases, a vast array of chemical by-products, and naturally occurring radioactive elements make coal much less desirable as an energy source than is generally accepted.

Second, coal ash is rich in minerals, including large quantities of aluminum and iron. These and other products of commercial value have not been exploited.

Third, large quantities of uranium and thorium and other radioactive species in coal ash are not being treated as radioactive waste. These products emit low-level radiation, but because of regulatory differences, coal-fired power plants are allowed to release quantities of radioactive material that would provoke enormous public outcry if such amounts were released from nuclear facilities. Nuclear waste products from coal combustion are allowed to be dispersed throughout the biosphere in an unregulated manner. Collected nuclear wastes that accumulate on electric utility sites are not protected from weathering, thus exposing people to increasing quantities of radioactive isotopes through air and water movement and the food chain.

Fourth, by collecting the uranium residue from coal combustion, significant quantities of fissionable material can be accumulated. In a few year's time, the recovery of the uranium-235 released by coal combustion from a typical utility anywhere in the world could provide the equivalent of several World War 11-type uranium-fueled weapons. Consequently, fissionable nuclear fuel is available to any country that either buys coal from outside sources or has its own reserves. The material is potentially employable as weapon fuel by any organization so inclined. Although technically complex, purification and enrichment technologies can provide high-purity, weapons-grade uranium-235. Fortunately, even though the technology is well known, the enrichment of uranium is an expensive and time-consuming process.

Because electric utilities are not high-profile facilities, collection and processing of coal ash for recovery

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Coal Combustion Page 8 of 10 of minerals, including uranium for weapons or reactor fuel, can proceed without attracting outside attention, concern, or intervention. Any country with coal-fired plants could collect combustion by-products and amass sufficient nuclear weapons material to build up a very powerful arsenal, if it has or develops the technology to do so. Of far greater potential are the much larger quantities of thorium-232 and uranium-238 from coal combustion that can be used to breed fissionable isotopes. Chemical separation and purification of uranium-233 from thorium and plutonium-239 from uranium require far less effort than enrichment of isotopes. Only small fractions of these fertile elements in coal combustion residue are needed for clandestine breeding of fissionable fuels and weapons material by those nations that have nuclear reactor technology and the inclination to carry out this difficult task.

Fifth, the fact that large quantities of uranium and thorium are released from coal-fired plants without restriction raises a paradoxical question. Considering that the U.S. nuclear power industry has been required to invest in expensive measures to greatly reduce releases of radioactivity from nuclear fuel and fission products to the environment, should coal-fired power plants be allowed to do so without constraints?

/Sde~mal7dw% hten ue can 6zectq s'n>ifen redxrc//Ž?/7 o/rz pfona/ocy n reMgdf7 ot radk~cfvas' e m/ssas trom =aUS7m~6&&/7 This question has significant economic repercussions. Today nuclear power plants are not as economical to construct as coal-fired plants, largely because of the high cost of complying with regulations to restrict emissions of radioactivity. If coal-fired power plants were regulated in a similar manner, the added cost of handling nuclear waste from coal combustion would be significant and would, perhaps, make it difficult for coal-burning plants to compete economically with nuclear power.

Because of increasing public concern about nuclear power and radioactivity in the environment, reduction of releases of nuclear materials from all sources has become a national priority known as "as low as reasonably achievable" (ALARA). If increased regulation of nuclear power plants is demanded, can we expect a significant redirection of national policy so that radioactive emissions from coal combustion are also regulated?

Although adverse health effects from increased natural background radioactivity may seem unlikely for the near term, long-term accumulation of radioactive materials from continued worldwide combustion of coal could pose serious health hazards. Because coal combustion is projected to increase throughout the world during the next century, the increasing accumulation of coal combustion by-products, including radioactive components, should be discussed in the formulation of energy policy and plans for future energy use.

One potential solution is improved technology for trapping the exhaust (gaseous emissions up the stack) from coal combustion. If and when such technology is developed, electric utilities may then be able both to recover useful elements, such as nuclear fuels, iron, and aluminum, and to trap greenhouse gas emissions. Encouraging utilities to enter mineral markets that have been previously unavailable may or may not be desirable, but doing so appears to have the potential of expanding their economic base, thus offsetting some portion of their operating costs, which ultimately could reduce consumer costs for electricity.

Both the benefits and hazards of coal combustion are more far-reaching than are generally recognized.

Technologies exist to remove, store, and generate energy from the radioactive isotopes released to the environment by coal combustion. When considering the nuclear consequences of coal combustion,

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,'Coal Combustion Page 9 of 10 policymakers should look at the data and recognize that the amount of uranium-235 alone dispersed by coal combustion is the equivalent of dozens of nuclear reactor fuel loadings. They should also recognize that the nuclear fuel potential of the fertile isotopes of thorium-232 and uranium-238, which can be converted in reactors to fissionable elements by breeding, yields a virtually unlimited source of nuclear energy that is frequently overlooked as a natural resource.

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/earrear l WI /oad 7gs In short, naturally occurring radioactive species released by coal combustion are accumulating in the environment along with minerals such as mercury, arsenic, silicon, calcium, chlorine, and lead, sodium, as well as metals such as aluminum, iron, lead, magnesium, titanium, boron, chromium, and others that are continually dispersed in millions of tons of coal combustion by-products. The potential benefits and threats of these released materials will someday be of such significance that they should not now be ignored.--Alex Gabbard of the Metals and Ceramics Division References and Suggested Reading J. F. Ahearne, "The Future of Nuclear Power," American Scientist, Jan.-Feb 1993: 24-35.

E. Brown and R. B. Firestone, Table of Radioactive Isotopes, Wiley Interscience, 1986.

J. 0. Corbett, "The Radiation Dose From Coal Burning: A Review of Pathways and Data," Radiation Protection Dosimetry, 4 (1): 5-19.

R R. Judkins and W. Fulkerson, "The Dilemma of Fossil Fuel Use and Global Climate Change," Energy

& Fuels, 7 (1993) 14-22.

National Council on Radiation Protection, Public Radiation Exposure From Nuclear Power Generation in the U.S., Report No. 92, 1987, 72-112.

National Council on Radiation Protection, Exposure of the Population in the United States and Canada from Natural Background Radiation, Report No. 94, 1987,90-128.

National Council on Radiation Protection, Radiation Exposure of the U.S. Population from Consumer Products and Miscellaneous Sources, Report No. 95, 1987, 32-36 and 62-64.

Serge A. Korff, "Fast Cosmic Ray Neutrons in the Atmosphere," Proceedings of International Conference on Cosmic Rays, Volume 5: High Energy Interactions, Jaipur, December 1963.

C. B. A. McCusker, "Extensive Air Shower Studies in Australia," Proceedings ofInternational Conference on Cosmic Rays, Volume 4: Extensive Air Showers, Jaipur, December 1963.

T. L. Thoem, et al., Coal Fired Power Plant Trace Element Study, Volume 1: A Three Station Comparison, Radian Corp.for USEPA, Sept. 1975.

W. Torrey, "Coal Ash Utilization: Fly Ash, Bottom Ash and Slag," Pollution Technology Review, 48 (1978) 136.

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-About Waste-to-Energy

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1 A 2oo4i Page 1 of 3 AM 0About Waste-to-Energy:

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Clean, Reliable, Renewable Power Choose a Subject Printable Versii What is "waste-to-energy?"

I Waste-to-energy facilities produce clean, renewable energy through the combustion of municipal solid waste in specially designed power plants equipped with the most modem pollution control equipment to clean emissions.

Trash volume is reduced by 90% and the remaining residue is regularly tested and consistent meets strict EPA standards allowing reuse or disposal in landfills. There are 89 waste-to-energy plants operating in 27 states managing about 13 percent of America's trash, or about 95,000 tons each day. Waste-to-energy generates about 2,500 megawatts of electricity to meet the power needs of nearly 2 million homes, and the facilities serve the trash disposal 4needs of more than 36 million people. The $10 billion waste-to-energy industry employs more S

than 6,000 American workers with annual wages in excess of $400 million.

Why is waste-to-energy clean?

America's waste-to-energy facilities meet some of the most stringent environmental standard, in the world and employ the most advanced emissions control equipment available. The EPA announced that America's waste-to-energy plants produce 'dramatic decreases" in air emissions, and produce electricity "with less environmental impact than almost any othet source of electricity." The "outstanding performance" of pollution control equipment usec by the waste-to-energy industry has produced 'dramatic decreases" in emissions. EPA data demonstrate that dioxin emissions have decreased by more than 99% in the past ten years, and represent less than one-half of one percent of the national dioxin inventory. Mercury emissions have declined by more than 95% and now represent two percent of the national inventory of man-made mercury emissions. Additionally, EPA estimates that waste-to-energy technology annually avoids 33 million metric tons of carbondioxide, a greenhouse gas, that would otherwise be released into the atmosphere.

Communities served by these facilities recycle an average of 35% of their trash as compared with the national recycling rate of 30%. Waste-to-energy annually removes for recycling more than 700,000 tons of ferrous metals and more than 3 million tons of glass, metal, plastics, batteries, ash and yard waste at recycling centers located on site.

Why is waste-to-energy renewable?

For more thanl twenty years, waste-to-energy has been recognized as a source of renewable energy under existing law. Waste-to-energy Is a "clean, reliable, renewable source of energy," according to the U.S. EPA The Federal Power Act, the Public Utility Regulatory Policies Act, the Federal Energy Regulatory Commission's regulations, and the Biomass Research anc Development Act of 2000 all recognize waste-to-energy power as renewable biomass, as dqo fifteen states that have enacted electric restructuring laws. EPA estimates 75' of trash contairs biomass on a Btu-output basis. Tuming garbage into energy makes "important contributions to the overall effort to achieve increased renewable energy ut and the many associated positive environmental benefits," wrote Department of Energy Assistant Secretary for Energy Efficiency and Renewable Energy, David Garman.

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'About Waste-to-Energy Page 2 of 3 What makes waste-to-energy reliable?

Waste-to-energy plants supply power 365-days-a-year, 24-hours a day. Facilities average greater than 90% availability of installed capacity. Waste-to-energy plants generally operate ii or near an urban area, easing transmission to the customer. Waste-to-energy power is sold a "base load' electricity. There is a constant need for trash disposal, and an equally constant, steady, and reliable energy generation. Waste-to-energy promotes energy diversity while helping cities meet the challenge of trash disposal.

How does waste-to-energy produce clean energy from dirty garbage?

Waste-to-energy facilities achieved compliance in 2000 with new Clean Air Act pollution control standards for municipal waste combustors. More than $1 billion was spent to upgrade waste-to-energy facilities, leading EPA to write that the 'upgrading of the emissions control systems of large combustors to exceed the requirements of the Clean Air Act Section 129 standards is an impressive accomplishment." In addition to combustion controls, waste-to-energy facilities employ sophisticated pollution control equipment.

• A "bag house" works like a giant vacuum cleaner with hundreds of fabric filter bags tha clean the air of soot, smoke and metals.

• A 'scrubber" sprays a slurry of lime into the hot exhaust. The lime neutralizes acid gases, just as a gardener uses lime to neutralize acidic soil. Scrubbing also can improN the capture of mercury in the exhaust.

• Selective Non-Catalytic Reduction" or 'SNCR" converts nitrogen oxides - a cause of urban smog - to harmless nitrogen by spraying ammonia or urea into the hot fumace.

• "Carbon Injection' systems blow charcoal into the exhaust gas to absorb mercury.

Carbon injection also controls organic emissions such as dioxins Ash residue from waste-to-energy facilities represents about 10% by volume of the original trash. The ash is tested in accordance with strict state and federal leaching tests and Is consistently shown to be safe for land disposal and reuse. Ash makes good cover in landfills because it exhibits concrete-like properties causing it to harden once it is placed and compacted in a landfill, reducing the potential for rainwater to leach contaminants from trash landfills into the ground. Nearly 3 million tons of waste-to-energy ash is beneficially reused as landfill cover, roadbed or building material.

About IWSA I IWSA Membership j Join IWSA On-Line I About Waste to Energy Worker Health & Safety I Conferences and Events I Links Copyright 2003-2004 Integrated Waste Services Association httn*/Airnyuy rt a

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North Carolina State Energy Plan June, 2003 Prepared for the North Carolina Energy Policy Council By the State Energy Office North Carolina Department of Administration And Appalachian State University Energy Center

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Demand Side Management Electric utilities have 2 means of meeting increases in customers' electricity demands: supply side management and demand side management. Supply side management consists of the utilities' plans and programs to increase the supply of electricity to meet the anticipated increases in demand, mainly through construction of new power plants. Demand Side Management (DSM) attempts to reduce the demand for electricity or to shift it to times away from the system peak so that the need for additional generation capacity is minimized. The plans of the IOUs and EMCs for meeting forecasted electricity demand are available to the public and are currently-reviewed by the North Carolina Utilities Commission in an annual integrated resource planning proceeding.

Typical DSM options have included:

+ Thermal efficiency in new and existing homes

• Residential high-efficiency heat pumps

• Interruptible residential central air conditioners/water heaters

• Commercial energy-efficient lighting, heating, and air conditioning in new and existing buildings Commercial thermal energy storage High-efficiency off-street security lighting Industrial energy audits with incentives for efficiency improvements Industrial time-of-use rates Large-load curtailment during peak load periods Remote-controlled voltage reduction To motivate customers to implement these options, utilities have offered financial incentives such as reduced electrical rates, rebates on the customers' bills, rebates for purchase and installation, and low-interest loans.

Demand side management programs were popular in the 1980's and early-to-mid 1990's. For example, in 1995, Progress Energy predicted a reduction of about 10.6% in system peak for the year, increasing to 13.4% in 2009 through demand side management activities. (4-7)

Electric utilities in North Carolina have changed the way in which they report the contribution of DSM programs. In the early and mid-1990s, reported DSM savings included all electric utility efforts to reduce the demand for electricity. However, in recent reports, DSM savings included only electric capacity that could be controlled directly by the utility - considerably less than the total of all DSM programs. This change in reporting procedures makes it difficult to compare previous projections of DSM programs with current estimates. Utility representatives agree that DSM programs have declined.

North Carolina Public Staff Viewpoint on Demand Side Management in 1990 "The Public Staff believes that special ratemaking treatment of DSM is appropriate in order to encourage utilities to aggressively invest in DSM resources. This special treatment includes three key elements: (1) the recovery of certain incurred costs associated with operating DSM programs; (2) the recovery of 'lost revenues resulting from energy efficiency programs; and (3) an additional financial incentive, or bonus, for exemplary DSM accomplish-ments."

Source: Docket No. E-100, Sub 64.

Stipulation between the Public Staff and Duke Power Company North Carolina State Energy Plan 23

Table 10:

Progress Energy Carolinas 1995 DSM Forecast Reference Case for North Carolina (Summer MW Reduction) 1995 2000 2005 2009 Residential 429 591 749 852 Load Control (from above) 216 345 481 571 Time-of-Day Rates 22 27 32 34 High Efficiency HP and AC 24 35 39 41 Home Energy Loan/ Conservation 34 39 42 43 Discount Common Sense Home 132 145 156 163 Commercial 157 206 285 329 Audit 58 77 124 149 Energy Efficient Design 97 125 155 172 Thermal Storage 3

4 6

7 Industrial 564 667 763 804 Large-Load Curtailment 212 236 254 268 Time of Use Rates & Thermal 116 138 149 158 Storage Audit/ Energy Efficient Plants 236 294 350 379 Total 1,151 1,464 1,787 1,986 Source: CP&L Integrated Resource Plan, April, 28,1995.

! In the past, utility DSM program had support of millions of dollars. In 1997, Duke predicted DSM program costs of about $66 million' for the year, $38 million for 2002, and about $39 million for 2011. In 1994, Progress Energy Carolinas forecast DSM management costs of $44 million, $47 million, and

$48 million for the years 1994 through 1996. Thus, the annual costs of DSM programs for both utilities combined were in the $80 to $100 million range, i equivalent to about one mil for every kWh sold in the state.

There are several reasons for the decline in DSM programs offered by utilies: 1) electric utility restructuring appeared imminent, so many utilities sought to lower costs in order to increase their competitive edge, 2) the cost of peak power plants, such as gas turbines, has become so low that they are less expensive than reductions in peak demand from DSM programs, and 3) some DSM programs were not able to provide the peak demand savings projected.

' 24 North Carolina State Energy Plan

\\,,

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'j '

ANNUAL REPORT of the NORTH UTILITIES CAROLINA COMMISSION Regarding Long Range Needs for Expansion of Electric Generation Facilities for Service in North Carolina

- July 2004 -

July 27, 2004 The Honorable Michael F. Easley Governor State of North Carolina Capitol Building Raleigh, North Carolina 27611

Dear Governor Easley:

The North Carolina Utilities Commission hereby presents for your consideration its Annual Report on the Long Range Needs for Expansion of Electric Generation Facilities for Service in North Carolina. This report is made to you and to the members of the Joint Legislative Utility Review Committee of the General Assembly pursuant to G.S. 62-1 10.1(c).

This report is an update of the Commission's last Report, dated July 2003, and is based on the most current reports of the electric utilities serving North Carolina and on the Commission's Order of March 23, 2004, in Docket No. E-100, Sub 98.

Very truly yours, Jo Anne Sanford, Chair JAS/RWE/mr

Copies of the Annual Report of the North Carolina Utilities Commission Regarding Long Range Needs for Expansion of Electric Generation Facilities for Service in North Carolina have been mailed to the following:

The Honorable Beverly Perdue Office of the Lieutenant Governor 310 N. Blount Street Raleigh, North Carolina 27603 The Honorable Marc Basnight President Pro Tem of the Senate North Carolina General Assembly 2007 State Legislative Building Raleigh, North Carolina 27601-1096 The Honorable James B. Black Speaker of the House of Representatives North Carolina General Assembly 2304 State Legislative Building Raleigh, North Carolina 27601-1096 The Honorable Richard T. Morgan Speaker of the House of Representatives North Carolina General Assembly 301 Legislative Office Building Raleigh, North Carolina 27603-5925 The Honorable David W. Hoyle North Carolina General Assembly Chair of Joint Legislative Utility Review Committee 300-A Legislative Office Building Raleigh, North Carolina 27603-5925 The Honorable Charlie Albertson North Carolina General Assembly Joint Legislative Utility Review Committee 525 Legislative Office Building Raleigh, North Carolina 27603-5925 The Honorable Charlie Dannelly North Carolina General Assembly Joint Legislative Utility Review Committee 2010 State Legislative Building Raleigh, North Carolina 27601-2808

The Honorable John A. Garwood North Carolina General Assembly Joint Legislative Utility Review Committee 1118 State Legislative Building Raleigh, North Carolina 27601-1096 The Honorable R. C. Soles, Jr.

North Carolina General Assembly Joint Legislative Utility Review Committee 2022 State Legislative Building Raleigh, North Carolina 27601-1096 The Honorable Harold Brubaker North Carolina General Assembly Co-Chair, Joint Legislative Utility Review Committee 1229 State Legislative Building Raleigh, North Carolina 27601-1096 The Honorable Drew P. Saunders North Carolina General Assembly Co-Chair, Joint Legislative Utility Review Committee 2217 State Legislative Building Raleigh, North Carolina 27601-1096 The Honorable Stephen Laroque North Carolina General Assembly Joint Legislative Utility Review Committee 417-B Legislative Office Building Raleigh, North Carolina 27603-5925 The Honorable Danny McComas North Carolina General Assembly Joint Legislative Utility Review Committee 506 Legislative Office Building Raleigh, North Carolina 27603-5925 The Honorable Thomas E. Wright North Carolina General Assembly Joint Legislative Utility Review Committee 528 Legislative Office Building Raleigh, North Carolina 27603-5925 Mr. Steven J. Rose Committee Counsel Joint Legislative Utility Review Committee 545 Legislative Office Building Raleigh, North Carolina 27603-5925

Ms. Kory Goldsmith Assistant Committee Counsel Joint Legislative Utility Review Committee 545 Legislative Office Building Raleigh, North Carolina 27603-5925 Ms. Penny N. Williams Committee Clerk Joint Legislative Utility Review Committee 300 Legislative Office Building Raleigh, North Carolina 27603-5925 Mr. Robert P. Gruber Executive Director North Carolina Utilities Commission - Public Staff 4326 Mail Service Center Raleigh, North Carolina 27699-4326 Ms. Margaret A. Force Assistant Attorney General North Carolina Department of Justice - Consumer Protection/Utilities P. 0. Box 629 Raleigh, North Carolina 27602 Mr. Larry E. Shirley Director, Energy Division North Carolina Department of Administration 1340 Mail Service Center Raleigh, NC 27699-1340 Progress Energy Carolinas Post Office Box 1551 Raleigh, North Carolina 27602-1551 Attention: Mr. Robert B. McGehee Chairman, President & CEO Duke Power, A Duke Energy Company 526 South Church Street Charlotte, North Carolina 28202 Attention: Ms. Ruth Shaw President Dominion North Carolina Power Post Office Box 26666 Richmond, Virginia 23261-6666 Attention: Mr. Jay L. Johnson President & CEO

New River Light and Power Company Post Office Box 1130 Boone, North Carolina 28607 Attention: Mr. Donald R. Austin General Manager Western Carolina University 530 H. F. Robinson Administration Building Cullowhee, North Carolina 28723 Attention: Mr. Richard Kucharski Legal Counsel North Carolina Electric Membership Corporation Post Office Box 27306 Raleigh, North Carolina 27611-7306 Attention: Mr. Thomas K. Austin Associate General Counsel ElectriCities of North Carolina Post Office Box 29513 Raleigh, North Carolina 27626-0513 Attention: Mr. Jesse C. Tilton, IlI CEO

TABLE OF CONTENTS

1. EXECUTIVE

SUMMARY

.............................................................. 1I

2. INTRODUCTION...............................................................

5

3. OVERVIEW OF THE ELECTRIC UTILITY INDUSTRY IN NORTH CAROLINA..........

........... 6

4. THE HISTORY OF INTEGRATED RESOURCE PLANNING IN NORTH CAROLINA..............................................................

9

5. LOAD FORECASTS AND PEAK DEMAND..............................................................

11

6. SUPPLY RESOURCES AND DEMAND-SIDE MANAGEMENT........................................ 13

7. RELIABILITY AND RESERVE MARGINS..............................................................

16

8. STATE ENERGY INITIATIVES AND JUDICIAL PROCEEDINGS.................................... 19

9. NC GREENPOWER...............................................................

20

10. MERCHANT PLANTS.............................................................. 22

11. FERC WHOLESALE MARKET PLATFORM AND REGIONAL TRANSMISSION ORGANIZATIONS.............................................................. 24 1 2. CONCLUSION...............................................................

27

1. EXECUTIVE

SUMMARY

This annual report to the Governor and the General Assembly is submitted pursuant to G.S.62-110.1(c), which specifies that each year the North Carolina Utilities Commission shall submit to the Governor and appropriate committees of the General Assembly a report of its analysis of the long-range needs for expansion of facilities for the generation of electricity in North Carolina, and a report on its plan for meeting those needs. Much of the information contained in this report is based on reports to the Commission by the electric utilities regarding their respective analyses and plans for meeting the demand for electricity in their respective service areas. It also reflects information from other records and files of the Commission.

There are three regulated investor-owned electric utilities (lOUs) and two university-owned utilities operating under the laws of the State of North Carolina and subject to the jurisdiction of the Commission. All three of the IOUs own generating facilities.

They are Carolina Power & Light Company, doing business as Progress Energy Carolinas, Inc. (Progress), whose corporate office is in Raleigh; Duke Power, a division of Duke Energy Corporation (Duke), whose corporate office is in Charlotte; and Virginia Electric and Power Company (VEPCO), whose corporate office is in Richmond, Virginia, and which does business in North Carolina under the name Dominion North Carolina Power (NC Power). Duke and Progress, the two largest electric lOUs in North Carolina, together supply about 95% of the utility-generated electricity consumed in the state.

Approximately 20% of the lOUs' total electric sales in North Carolina are to the wholesale market, consisting primarily of electric membership corporations and municipally-owned electric systems. That portion of the forecast future electric needs of the North Carolina wholesale market that the IOUs expect to supply is included in their integrated resource plans.

Table ES-1 shows the electricity sales of the regulated utilities in North Carolina.

1

Table ES-1: Electricity Sales of Regulated Utilities In North Carolina NC Retail GWh*

NC Wholesale Total GWh Sales*

GWh*

(NC Plus Other States) 2003 2002 2003 2002 2003 2002 Progress 34,858 35,327 14,487 14,146 57,470 57,527 Duke 53,025 53,984 8,439 7,466 82,828 83,783 NC Power 3,876 3,861 1,279 1,433 76,069 76,101 New River 212 212 0

0 212 212 Western Carolina 30 30 0

0 30 30

• GWh = 1 Million kWh During the period from 1990 to 2000, the average annual growth rate in summer peak demand for' electricity was approximately 3.0%.

Forecasts for the 2004 to 2013 timeframe predict that this rate will drop to just under 2.0%. Table ES-2 below illustrates the systemwide average annual rates of growth forecast by the lOUs that operate in North Carolina.

Their forecasts are relatively typical for electric utilities serving the Southeastern states. Each uses generally accepted forecasting procedures and, although their forecasting models are different, the econometric techniques employed by each are widely used for projecting future trends. Under normal weather patterns, the summer peak demand remains dominant over the winter peak demand for all three lOUs.

Table ES-2: Forecast Annual Growth Rates for Progress, Duke, (2004-2013) and NC Power Summer Average Winter Energy Peak Summer Peak Peak Sales MW Growth Progress 1.9%

216 1.9%

1.7%

Duke 1 7%

309 1.2%

1.6%

NC Power 1.8%

305 1.5%

1.9%

North Carolina's utilities depend on coal-fired and nuclear-fueled steam generation to produce the overwhelming majority of their electric output, as illustrated in Table ES-3. It should be noted that the purchased power listed in the table includes buyback transactions associated with jointly owned coal and nuclear plants.

2

Table ES-3: Total Energy Resources by Fuel Type for 2003 Progress Duke NC Power Coal 48%

50%

41%

Nuclear 41%

46%

31%

Net Hydroelectric 2%

2%

1%

Oil and Natural Gas 2%

0%

10%

Purchased Power 7%

2%

17%

Demand-side management (DSM) resources, including conservation and load-management measures, play a role in meeting the energy and demand requirements of electric utility systems by controlling existing and future loads.

Progress, Duke, and NC Power have used a variety of programs, such as bill credits for interruptible loads, cash incentives and/or low interest loans to encourage customers to install higher efficiency equipment, and special rate designs. These programs, which are voluntary, are intended to lower the electric bills of participating customers and reduce overall electricity costs to the remainder of the utility system.

Based on information contained in their current Integrated Resource Plans (IRPs),

Progress, Duke, and NC Power expect to achieve DSM summer peak load reductions as shown in Table ES-4.

Table ES-4: Projected DSM Summer System Peak Load Reductions 2004 2013 MW

% of Total Peak MW

% of Total Peak Requirements Requirements Progress 372 3.3%

384 2.9%

Duke 796 4.4%

734 3.5%

NC Power 38 0.2%

38 0.2%

Current reliability assessments by the North American Electric Reliability Council (NERC) project that the Southeastern region will have adequate reserve margins over the next ten years.

Progress, Duke, and NC Power are projecting reserve margins that are typical for electric utilities serving the Southeastern states and similar to the reserve margins they have maintained in the recent past. Each of the utilities bases its projected reserve margin on a significant amount of undesignated resources.

Progress shows 1,800 MW of undesignated generating capacity additions in its IRP, and Duke includes 4,500 MW. NC Power projects 3,500 MW of undesignated market purchases that could become Company construction projects, depending on future economic conditions.

3

Uncertainty regarding the resolution of two important issues involving the authority of the Commission makes it somewhat more difficult to chart a long-range plan for the future. First, the North Carolina Supreme Court will decide whether the Commission has authority to review, before they are signed, proposed utility contracts for the sale of wholesale power at native load priority to be supplied from the same generating plants used to serve utility retail ratepayers. The second issue is the extent of State authority over the formation of regional transmission organizations compared to that of the Federal Energy Regulatory Commission (FERC). These issues are discussed in sections eight and eleven of this report.

A map showing the service areas of the North Carolina lOUs is attached to this report.

4

2. INTRODUCTION The General Statutes of North Carolina require that the Utilities Commission analyze the probable growth in the use of electricity and the long-range need for future generating capacity in North Carolina. The General Statutes also require the Commission to submit an annual report to the Governor and to the General Assembly regarding future electricity needs. G.S.62-110.1(c) provides, in part, as follows:

The Commission shall develop, publicize, and keep current an analysis of the long-range needs for expansion of facilities for the generation of electricity in North Carolina, including its estimate of the probable future growth of the use of electricity, the probable needed generating reserves, the extent, size, mix and general location of generating plants and arrangements for pooling power to the extent not regulated by the Federal Power Commission and other arrangements with other utilities and energy suppliers to achieve maximum efficiencies for the benefit of the people of North Carolina, and shall consider such analysis in acting upon any petition by any utility for construction.... Each year, the Commission shall submit to the Governor and to the appropriate committees of the General Assembly a report of its analysis and plan, the progress to date in carrying out such plan, and the program of the Commission for the ensuing year in connection with such plan.

Some of the information necessary to conduct the analysis of the long-range needs for future electric generating capacity required by G.S.62-110.1(c) is filed by each regulated utility as a part of the Least Cost Integrated Resource Planning process.

Commission Rule R8-60 defines an overall framework within which least cost integrated resource planning takes place. Commonly called Integrated Resource Planning (IRP), it is a process that takes into account conservation, load management, and other demand-side options along with. new utility-owned generating plants, non-utility generation, and other supply-side options in order to identify the resource plan that will be most cost-effective for the ratepayers consistent with the provision of adequate, reliable service.

This report is an update of the Commission's July 2003 Annual Report. It is based primarily on reports to the Commission by the regulated electric utilities serving North Carolina, but also includes information from other records and files of the Commission.

Much of the material was gathered in Docket No. E-100, Sub 98, Investigation of Integrated Resource Planning in North Carolina - 2003. A final Order Approving the Integrated Resource Plans of North Carolina's electric utilities was issued in that docket on March 23, 2004, and is attached to this report.

5

3. OVERVIEW OF THE ELECTRIC UTILITY INDUSTRY IN NORTH CAROLINA There are three regulated investor-owned electric utilities (IOUs) and two university-owned utilities operating in North Carolina subject to the jurisdiction of the Commission. All three of the IOUs own generating facilities. They are Carolina Power &

Light Company, doing business as Progress Energy Carolinas, Inc. (Progress), whose corporate office is in Raleigh; Duke Power, a division of Duke Energy Corporation (Duke),

whose corporate office is in Charlotte; and Virginia Electric and Power Company (VEPCO),

whose corporate office is in Richmond, Virginia, and which does business in North Carolina under the name Dominion North Carolina Power (NC Power).

Duke and Progress, the two largest IOUs, together supply about 95% of the utility generated electricity consumed in the state. Duke has 1,695,000 customers located in North Carolina, and Progress has 1,145,000. Each also has customers in South Carolina.

NC Power supplies approximately 5% of the state's utility generated electricity. It has 115,000 customers in North Carolina. The main portion of its corporate operations are in Virginia, where it does business under the name of Dominion Virginia Power.

A map outlining the areas served by the lOUs is attached to this report.

The two remaining electric utilities subject to the Commission's jurisdiction are very small companies wholly located in North Carolina. Both are university-owned: New River Light and Power, located in Boone, and Western Carolina University, located in Cullowhee.

New River Light & Power is an all-requirements customer of Blue Ridge Electric Membership Corporation, and Western Carolina University is an all-requirements customer of Duke.

About 20% of the IOUs' North Carolina electric sales are to the wholesale market, consisting primarily of electric membership corporations and municipally-owned electric systems. That portion of the forecast future electric needs of the North Carolina wholesale market that the lOUs expect to supply is included in their Integrated Resource Plans.

Supply for the remainder of the forecast wholesale market is the responsibility of the wholesale entities.

Based primarily on annual reports (FERC Form 1) to the Commission for the 2003 reporting period, the gigawatt-hour (GWh) sales for the electric utilities in North Carolina are summarized in Table 1.

6

Table 1: Electricity Sales of Re ulated Utilities In North Carolina NC Retail GWh*

NC Wholesale Total GWh Sales*

GWh*

(NC Plus Other States) 2003 2002 2003 2002 2003 2002 Progress 34,858 35,327 14,487 14,146 57,470 57,527 Duke 53,025 53,984 8,439 7,466 82,828 83,783 NC Power 3,876 3,861 1,279 1,433 76,069 76,101 New River 212 212 0

0 212 212 Western Carolina 30 30 0

0 30 30

• GWh = 1 Million kWh The Commission does not regulate the rates of municipally-owned electric systems or electric membership corporations; however, the Commission does have jurisdiction over the licensing of all new electric generating plants and large scale transmission facilities built in North Carolina. Commission Rule R8-60(b) specifies that the IRP process is applicable to the North Carolina Electric Membership Corporation (NCEMC), though the Commission has concluded that it was not necessary, or appropriate, to include individual electric membership corporations (EMCs) in its IRP proceedings.

EMCs are independent, non-profit corporations.

There are 32 EMCs serving 899,000 customers in North Carolina, including 27 that are headquartered in the state. The other five are headquartered in adjacent states. These EMCs serve customers in 96 of the state's 100 counties. Twenty-six of the EMCs are members of NCEMC, an umbrella service organization. NCEMC is a generation and transmission services cooperative that provides wholesale power and other services to these 26 members. Individual NCEMC member cooperatives operate less than one MW of their own generation.

There are six distribution cooperatives operating in the state that are not members of NCEMC. As noted above, five are incorporated in contiguous states and provide service in limited areas across the border into North Carolina. The sixth is French Broad EMC, which has agreed to provide appropriate information to NCEMC for inclusion in NCEMC's IRP filings.

NCEMC's total load growth in North Carolina is projected to be approximately 2.2%

per year during the 2004-2013 summer seasons (See Appendix 5).

NCEMC owns approximately 662 MW of generation resources, consisting of 644 MW from Duke's Catawba Nuclear Station plus 18 MW from two small diesel-powered peaking plants (at Ocracoke Station and at Buxton Station) on the Outer Banks. These facilities currently cover about 25% of NCEMC's projected peak demand requirements. Additionally, many of the member EMCs receive an allocation of hydroelectric power from the Southeastem 7

Power Administration (SEPA). The total hydroelectric capacity provided by SEPA is currently about 80 MW.

In June 2003, exercising their right to cease full participation in the power, supply program of NCEMC, four of the 26 distribution cooperatives gave notice that they would become responsible for their future power supply resources. They are Blue Ridge EMC, EnergyUnited, Piedmont EMC and Rutherford EMC. These four are now referred to by NCEMC as Independent Members. As a result, the NCEMC load forecast has been revised to reflect only the future loads of the remaining 22 members, referred to as Participating Members, along with its obligations to supply capacity and energy to the four Independent Members from existing power supply resource commitments.

The service territories of NCEMC's member EMCs are located within the control areas of Progress, Duke, and NC Power. Therefore, NCEMC's system consists of three distinct areas known as supply areas. In the past, NCEMC planned for each of these supply areas separately, primarily serving load with all requirements purchase power contracts with the control area power supplier.

Renegotiation of certain power supply contracts and the introduction of new resources to NCEMC's power supply portfolio, have provided the flexibility to serve load in multiple supply areas using the same resource.

NCEMC's ultimate goal is to serve all its members as a single system. As part of its plan, NCEMC expects to build approximately 900 MW of generating facilities divided among three sites.

In addition to receiving power from Progress, Duke, NC Power, and SEPA, NCEMC currently purchases wholesale electricity from Appalachian Power Company (APC),

American Electric Power Service Corporation (AEP), South Carolina Electric & Gas Company (SCE&G), and Southern Power Company (SPC). NCEMC has and will continue to ensure system reliability through either purchasing reserves as part of its power supply contracts or procuring the necessary reserves independently.

Like the lOUs, NCEMC is a member of the Virginia and Carolinas Regional Reliability Council (VACAR), a subregion of the Southeastern Electric Reliability Council (SERC), and participates on several committees of those councils. NCEMC also participates in and closely monitors activities related to the formation of Regional Transmission Organizations (RTOs), which are discussed later in this report.

NCEMC notes that these efforts are particularly important to it because of NCEMC's status as a transmission-dependent utility that relies on Duke, Progress, and NC Power to transmit the power it generates and the power it purchases to the 193 delivery points of its Participating Member EMCs.

In addition to the EMCs, there are 72 municipally-owned electric distribution systems serving over 533,000 customers in North Carolina.

These systems are members of ElectriCities, an umbrella service organization for the cities. ElectriCities is a non-profit organization that provides many of the technical, administrative, and management services needed by its 98 municipally-owned electric utility members in North Carolina, South 8

Carolina, and Virginia on a consolidated basis. New River Light and Power and Western Carolina University, the two smallest regulated utilities, are also members of ElectriCities.

ElectriCities is a service organization, not a power supplier.

Fifty-one of the North Carolina municipals are participants in one of two municipal power agencies which provide wholesale power to their membership. ElectriCities' largest activity is the management of these two power agencies.

The remaining 21 cities buy their own power at wholesale.

They are retail distributors of electricity.

One agency, the North Carolina Eastern Municipal Power Agency (NCEMPA), is the wholesale supplier to 32 cities and towns in eastern North Carolina.

NCEMPA owns portions of five Progress generating units (661 MW of fossil and nuclear capacity).

NCEMPA entered into a Supplemental Load Agreement with Progress for the period January 1, 2004 through December 31, 2009. The contract provides for additional power when needs exceed the capacity NCEMPA owns. It represents approximately 25% to 30%

of NCEMPA's total annual energy needs and roughly 35% to 40% of NCEMPA's average monthly capacity requirements.

The other power agency is North Carolina Municipal Power Agency Number 1 (NCMPA1), which is the wholesale supplier to 19 cities and towns in the western area of the state.

NCMPA1 has a 75% ownership interest (847 MW) in the Catawba Nuclear Station Unit 2 operated by Duke. It also has an exchange agreement with Duke that gives NCMPA1 access to power from the McGuire Nuclear Station and Catawba Unit 1.

NCMPA1 purchases power through bilateral agreements with other generators for its requirements above its Catawba entitlement.

To meet its supplemental power requirements, NCMPA1 entered into a contract with Georgia Power Company for the purchase of 125 MW and has the right to schedule and receive 60 MW of power from SEPA. In addition, NCMPA1 has purchased 50 MW of firm capacity from Dynegy Power Marketing, Inc., from its Rockingham County, North Carolina units.

In late 2002, NCMPA1 completed negotiations for a new power supply contract with Southern Company. Southern now serves as NCMPA1's power resource manager and will be responsible for meeting all of the Agency's energy needs and for marketing surplus energy.

4. THE HISTORY OF INTEGRATED RESOURCE PLANNING IN NORTH CAROLINA Integrated resource planning is an overall planning strategy which examines conservation, load management, and other demand-side measures in addition to the use of utility-owned generating plants, non-utility generation, and other supply-side resources in order to determine the least cost way of providing electric service. The primary purpose of 9

integrated resource planning is to integrate both demand-side and supply-side resource planning into one comprehensive procedure that weighs the costs and benefits of all reasonably available options in order to identify those which can be most cost-effective for the ratepayers consistent with providing adequate, reliable service.

By Commission Order dated December 8, 1988, in Docket No. E-100, Sub 54, Commission Rules R8-56 through R8-61 were adopted to define the framework within which integrated resource planning takes place. Those rules incorporated the analysis of probable electricity load growth with the development of a long-range plan for ensuring the availability of adequate electric generating capacity in North Carolina as required by G.S.62-110.1(c).

The first IRPs by the electric utilities were filed with the Commission in April 1989. In May of 1990, the Commission issued an Order in which it found that the initial IRPs of Progress, Duke, and NC Power were reasonable for purposes of that proceeding and that NCEMC should be required to participate in all future IRP proceedings.

By an Order issued in December 1992, Rule R8-62 was added. It covers the construction of electric transmission lines.

The Commission subsequently conducted a second and third full analysis and investigation of utility IRP matters resulting in the issuance of Orders Adopting Least Cost Integrated Resource Plans on June 29, 1993, and on February 20, 1996. A subsequent round of comments included a general endorsement of a proposal that the two/three year IRP filings, plus annual updates and short-term action plans, be replaced by a single annual filing. There was also general support for a shorter planning horizon than the fifteen years required at that time.

In April 1998, the Commission issued an Order in which it repealed Rules R8-56 through R8-59 and revised Rules R8-60 through R8-62 governing the IRP process. The new rules shortened the reported planning horizon from 15 to ten years and streamlined the IRP review process while retaining the filing of an annual plan by each utility in sufficient detail to allow the Commission to continue to meet its statutory responsibilities under G.S.62-110.1 (c) and G.S. 62-2(3a).

In September 1998, the first IRP filings were made under the revised rules. The Commission concluded as a part of its Order ruling on these filings that the reserve margins forecast by Progress, Duke, and NC Power indicated a much greater reliance upon off-system purchases and interconnections with neighboring systems to meet unforeseen contingencies than had been the case in the past. The Commission stated that it would closely monitor this issue in future IRP reviews.

In June 2000, the Commission stated in response to the lOUs' 1999 IRP filings that it did not believe that it was appropriate to mandate the use of any particular reserve margin for any jurisdictional electric utility at that time. The Commission concluded that it would be more prudent to monitor the situation closely, to allow all parties the opportunity to address 10

this issue in future filings with the Commission, and to consider this matter further in subsequent integrated resource planning proceedings.

The Commission did, however, want the record to clearly indicate its belief that providing adequate service is a fundamental obligation imposed upon all jurisdictional electric utilities, that it would be actively monitoring the adequacy of existing electric utility reserve margins, and that it would take appropriate action in the event that any reliability problems developed.

The most recent round of IRP filings in Docket No. E-100, Sub 98, resulted in the Commission's March 23, 2004 Order Approving Integrated Resource Plans.

The Commission reiterated its comments from previous proceedings regarding reserve margins, concluding that existing generation resources are adequate in light of current conditions. A copy of the March 23, 2004, Order is attached as Appendix 1.

5. LOAD FORECASTS AND PEAK DEMAND Forecasting electric load growth into the future is imprecise at best. Virtually all forecasting tools commonly used today assume that certain historical trends or relationships will continue into the future, and that historical correlations give meaningful clues to future usage patterns. As a result, any shift in such correlations or relationships can introduce significant error into the forecast.

Progress, Duke, and NC Power each utilize generally accepted forecasting procedures. Although their respective forecasting models are different, the econometric techniques employed by each utility are widely used for projecting future trends. Each of the models requires the analysis of large amounts of data, the selection of a broad range of demographic and economic variables, and the use of advanced statistical techniques.

With the inception of Integrated Resource Planning, North Carolina's electric utilities have attempted to enhance forecasting accuracy by performing end-use forecasts. While this approach relies on historical information, it includes specific electrical usage and consumption patterns in addition to general economic relationships.

Table 2 illustrates the systemwide average annual growth rates in energy and peak loads anticipated by Progress, Duke, and NC Power. The growth rates are based on the utilities' system peak load requirements. Detailed load projections for the respective utilities are shown in Appendices 2, 3 and 4. Uncertainties concerning the timing and predictability of the various demand reduction techniques make it necessary to allow flexibility in planning for generation capacity expansion to match predicted peak load forecasts. Under normal weather patterns, the annual summer peak demand remains dominant over the winter peak demand.

11

Table 2: Forecast Annual Growth Rates for Progress, Duke, and NC Power (2004-2013)

Summer Average Summer Peak Winter Energy Peak MW Growth Peak Sales Progress 1.9%

216 1.9%

1.7%

Duke 1.7%

309 1.2%

1.6%

NC Power 1.8%

305 1.5%

1.9%

North Carolina utility forecasts of future electrical energy usage are consistent with forecasts of utilities in neighboring states and about the same as the nation as a whole.

The 2003-2012 Reliability Assessment by the North American Electric Reliability Council (NERC) indicates that the national forecast of average annual growth in summer peak demand for the period is 1.9%. This number is down slightly from the 2.0% shown in NERC's prior year report and down significantly from the 2.4%

growth rate experienced over the last ten years.

After the 1973 Arab oil embargo, the electric utilities began initiating certain conservation and load management measures to control the growth in both peak demand and energy usage. Most of the programs in effect today were implemented in the 1970s and 1980s. Without these demand-side management programs, growth in peak demand would have been greater than actually recorded.

For the period from 1990-2000, the average annual growth rate in summer peak demand for the IOUs was approximately 3.0%. Table 3 provides historical peak load information.

The 2003 numbers were taken from the Public Staffs weekly Reserve Situation Reports.

Table 3: Summer and Winter Systemwide Peak Loads for Progress, Duke, and NC Power Since 1990 (in MW)

Progress Duke NC Power Summer Winter*

Summer Winter*

Summer Winter*

1990 8,681 7,875 14,046 12,778 12,113 11,076 1995 10,155 9,810 16,888 15,855 14,003 14,910 2000 11,106 11,140 18,773 16,181 15,410 14,729 2001 11,376 9,813 18,105 14,987 16,515 14,188 2002 11,978 11,977 18,040 16,075 17,084 16,133 2003 11,773 10,388 16,983 14,287 16,261 15,501

• Winter peak followina summer peak 12

6. SUPPLY RESOURCES AND DEMAND-SIDE MANAGEMENT Traditionally, the regulated electric utilities in North Carolina have met customer demand by installing their own generating capacity. These generating plants are usually classified by fuel type (nuclear, coal, gas/oil, and hydro) and placed into three categories of operation:

(1) Base load - operates nearly full cycle; (2) Intermediate - cycles with load increase and decrease; and (3) Peaking - operates infrequently to meet system peak demand.

Nuclear and large coal facilities serve as base load plants and typically operate more than 5000 hours0.0579 days <br />1.389 hours <br />0.00827 weeks <br />0.0019 months <br /> annually. Smaller and older coal and oil/gas plants are used as intermediate load plants and typically operate between 1,000 and 5,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> per year.

Finally, combustion turbines and other peaking plants usually operate less than 1,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> per year.

Hydroelectric generation facilities fall into two categories. The first, and by far the most common, are sometimes called run-of-the-river facilities and exist where a dam is used to create a barrier across a waterway to control the water flow, or raise the level of the water, which is then used to drive a water wheel which generates the electricity. The second type of hydro generation is called pumped storage. Both Duke and NC Power have this kind of facility in addition to regular dam-based hydro generating plants.

Pumped storage is the only method now in commercial use for large-scale storage of electricity. Excess electricity produced at times of low demand is used to pump water from a lower reservoir up and into a higher reservoir. When demand is high, this water is released and used to operate hydroelectric generators that produce supplemental electricity. Pumped storage returns only about two-thirds to three-fourths of the electricity used to pump the water up to the higher reservoir, but it costs less than an equivalent amount of additional generating capacity. This overall loss of energy is also a 'reason why the total "net" hydroelectric generation reported by a utility with pumped storage can be significantly less than that utility's actual percentage of hydroelectric generating capacity.

Another source of electric generation in North Carolina is non-utility generation. In 1978, Congress passed the Public Utility Regulatory Policies Act (PURPA), which established a national policy to encourage the efficient use of renewable fuel sources and cogeneration (production of electricity as well as another useful energy byproduct - generally steam - from a given fuel source). North Carolina electric utilities regularly utilize non-utility, PURPA-qualified, purchased power as a supply resource.

An additional source of renewable generation comes from a new program called NC GreenPower, which is a voluntary program that uses financial contributions from North Carolina citizens and businesses to help offset the cost of producing "green energy." This program is discussed in section nine of this report. Another portion of non-utility generation 13

comes from merchant plants. This source of electric power is growing in significance and is covered separately in section ten of this report.

The Commission recognizes the need for a mix of base load, intermediate, and peaking facilities and believes that onservation, load management, and the development of alternative energy resources and demand-side options must all play a significant role in meeting the capacity needs of each utility.

The current capacity mix of each IOU is shown in Table 4.

Table 4: Installed Generating Capacity by Fuel Type (Summer Ratings) for 2003 Progress Duke NC Power Coal

-43%

39%

33%

Nuclear 27%

35%

23%

Hydroelectric 2%

14%

11%

Oil and Natural Gas 28%

12%

33%

The actual generation mix (based on MWh generated) for each utility reflects the operation of the capacity shown above, plus outside purchases, and the operating efficiencies achieved by utilizing each source of power as close to the optimum level as possible.

Generally, plant use is determined by economic dispatch, meaning that the start-up, shutdown, and allocation of individual generating units is tied to specific loads in order to attain the most cost effective production of electricity. The actual generation produced and power purchased for each utility (based on monthly fuel reports filed with the Commission) are provided in Table 5.

Table 5: Total Energy Resources by Fuel Type for 2003 l

Progress Duke NC Power Coal 48%

50%

41%

Nuclear 41%

46%

31%

Net Hydroelectric 2%

2%

1 %

Oil and Natural Gas 2%

0%

10%

Purchased Power 7%

2%

17%

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The purchased power shown above includes buyback transactions associated with jointly owned coal and nuclear plants. The percentage of generation (MWh) from coal and nuclear units typically exceeds the percentage of generating capacity (MW) represented by such units, reflecting the use of these units for base-load generation. On the other hand, oil and natural gas fired combustion turbine units usually contribute a small amount of actual generation, although they represent a significant percentage of the generating capacity available to each utility, reflecting the use of combustion turbines primarily for peak-load generation and standby capacity.

Each utility identified projected new capacity additions in their September 2003 Integrated Resource Plans. Progress currently has 12,327 MW of installed generating capacity (summer rating), including 661 MW jointly-owned with NCEMPA and excluding purchases and non-utility capacity.

The Company proposes to add 2,040 MW of new capacity during 2004-2013. This includes 1,814 MW of undesignated capacity. It does'not plan to retire any existing units.

Duke currently has 19,925 MW of installed generating capacity (summer rating),

excluding purchases and non-utility capacity, but including 847 MW jointly-owned with NCMPA1 and 644 MW jointly-owned with NCEMC. Duke proposes to add 8 MW of new capacity during 2004-2013. This addition comes from an uprate-on the Nantahala Hydro Unit. It also plans to retire 591 MW of existing generating capacity.

It is forecasting 4,497 MW in cumulative future peaking/intermediate resource additions by 2013. These additions are undefined.

NC Power currently has 15,254 MW of installed generating capacity (summer rating),

excluding purchases and non-utility capacity. It proposes to add 27 MW of upgraded hydro capacity during the 2004-2013 timeframe. It does not plan to retire any existing units from service. NC Power also includes 3,497 MW of undesignated market purchases in their IRP plan which could, if economical, become Company construction projects.

Demand-side management (DSM) resources, including conservation and load management measures, play a role in meeting the energy and demand requirements of electric utility systems by controlling future loads. Progress, Duke, and NC Power have used a variety of programs, such as bill credits for interruptible loads, cash incentives and/or low interest loans to encourage customers to install higher efficiency equipment, and special rate designs. These programs, which are voluntary, are intended to lower the electric bills of participating customers and reduce overall electricity costs to the remainder of the utility system.

Based on information contained in their current IRPs, Progress, Duke, and NC Power expect to achieve DSM summer peak load reductions as shown in Table 6.

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Table 6: Projected DSM Summer System Peak Load Reductions 2004 2013 MW

% of Total Peak MW

% of Total Peak Requirements Requirements Progress372 3.3%

384 2.9%

Duke 796 4.4%

734 3.5%

NC Power 38 0.2%

38 0.2%

7. RELIABILITY AND RESERVE MARGINS Reliability of electric power supply is the ability of an electric system to continuously supply all of the demands of its consumers with a minimum interruption of service. It is also the ability of an electric system to withstand sudden disturbances, such as short circuits or sudden loss of system components due to scheduled or unscheduled outages.

The reliability of an electric system is a function of the number, size, fuel type, and age of the utility's power plants, the different types and numbers of interconnections the utility has with its neighboring electric utilities, and the environment to which its distribution and transmission systems are exposed.

There are several measurements of reliability utilized in the electric utility industry.

Generally, they are divided between probabilistic measures (loss of load probability, frequency, and duration of outages) and non-probabilistic measures (reserve margin and capacity margin). One of the most widely used measures is the reserve margin.

The reserve margin is the ratio of reserve capacity to actual needed capacity (i.e., peak load). It provides an indicator of the ability of an electric utility system to continue to operate despite the loss of a large block of capacity (generating unit outage and/or loss of a transmission facility), deratings of generating units in operation, or actual load exceeding forecast load. A similar indicator is capacity margin, which is the ratio of reserve capacity to total overall capacity (i.e., reserve capacity plus actual needed capacity). A 20% reserve margin is the same as a 16.7% capacity margin. Although reserve margin was the exclusive industry standard term for many years, capacity margin has also been used in recent years. This report continues to utilize reserve margin terminology.

It is difficult, if not impossible, to plan for major generating capacity additions in such a manner that constant reserve margins are maintained. Reserve margins will generally be lower just prior to placing new generating units into service and greater just after new generating units come online.

In earlier years, a 20% reserve margin was considered appropriate for long-range planning purposes. In recent years, the Commission has approved IRPs containing less than 20% reserve margins for substantial periods into the future. This is because of the 16

increased availability of emergency power supplies from the interconnection of electric power systems across the country, the increasing efficiency with which existing generating units have been operated, and the relative size of utility generating units compared to overall load.

Forecasted yearly reserves for Progress, Duke, and NC Power are contained in Appendices 2, 3, and 4. The summer reserve margins currently projected by each electric utility are illustrated in Table 7. They are comparable to those shown in last years report.

Table 7: Projected Reserves for Progress, Duke, and NC Power (2004-2013)

Reserve Margins Progress 14 - 17%

Duke 17%

NC Power 12.5%

For many years, it has been a federal policy to encourage interconnection and coordination among electric utilities in order to conserve energy, make more efficient use of facilities and resources, and increase reliability. NERC was formed by the electric power industry in 1968 to promote the reliability of bulk electric power supply in North America.

NERC consists of ten regional reliability councils, which together encompass virtually all of the electric power systems in the United States and Canada.

Historically, NERC, a not-for-profit corporation, has relied on voluntary efforts and what it refers to as "peer pressure" to ensure compliance with its standards, but this situation is widely considered inadequate. NERC does not currently have the authority to penalize or take other direct enforcement action against any entity violating a reliability standard.

On August 14, 2003, an electric power blackout affected large portions of the Northeastern and Midwestern United States and Ontario, Canada.

No North Carolina electric customer was adversely affected by this blackout, since the utility's operating systems worked as planned to prevent this event from affecting our state. The following day, a U.S.-Canada Power System Outage Task Force was established to investigate the causes of the blackout and recommend measures to reduce the possibility of future outages.

The Final Report, issued April 5, 2004, identified four categories of causes:

(1) inadequate system understanding, (2) inadequate situational awareness, (3) inadequate tree trimming, and (4) inadequate reliability coordinator diagnostic support. The Final Report found that several entities violated NERC operating policies and planning standards, directly contributing to the blackout. However, the Report also found that many of NERC's policies are unclear and ambiguous.

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On April 14, 2004, the Federal Energy Regulatory Commission (FERC) issued a policy statement on power system reliability that addressed the need to expeditiously modify NERC's reliability standards in order to make these standards clear and enforceable.

The FERC emphasized the importance of public utility compliance with reliability standards, stating that good utility practice includes compliance with these standards. The policy stated that the FERC, subject to existing limits on its authority, would consider taking utility-specific action on a case-by-case basis to address significant reliability problems or non-compliance with good utility practice. The policy statement also addressed recovery of prudent reliability costs and the need for communication and cooperation between the FERC and the states, as well as with Canada and Mexico.

The FERC's policy statement emphasized that it supports NERC and the industry in their efforts to make reliability standards clearer and more enforceable. Priority matters identified in the Final Report that need to be addressed in the NERC standards include issues such as vegetation management on transmission rights-of-way, operator training, and adequacy of operator tools.

The Southeastern Electric Reliability Council (SERC) is one of the ten NERC regional reliability councils.

Its 38 regular members and 26 associate members include investor-owned utilities, electric cooperatives, municipally-owned utilities, federal and state-owned systems, independent power producers, and power marketers.

SERC is divided into four subregions and covers portions of 13 southeastern states: Southern (composed mostly of the Southern Company electric system centered in Georgia, Alabama, and Mississippi), TVA (containing the Tennessee Valley Authority area), VACAR (containing the Virginia-Carolinas area), and Entergy (containing primarily the Entergy operating areas in Louisiana, Arkansas and Missouri). VACAR consists of the Progress, Duke, and NC Power operating areas, in addition to the operating areas of other utilities serving portions of Virginia, North Carolina, and South Carolina.

The 2003-2012 Reliability Assessment by NERC indicates that the summer reserve margins for the SERC region will range between 12.6% to 15.9% during the 2004-2008 period. It projects that SERC will have adequate reserve margins and capacity resources during the period. Over the next ten years, the average annual summer peak demand growth rate for the entire SERC area is forecast to be 2.3%. By contrast, the average annual demand growth rate for the VACAR subregion is forecast to be 2.0%. The actual SERC growth rate over~the last ten years averaged 2.9%. The SERC forecast growth rate for overall energy usage during the next ten years is 2.1% compared to an historical growth rate for the last ten years of 2.8%.

Since the addition of new generating capacity in much of the United States is driven more by market signals than the need to maintain adequate reserve margins, much uncertainty surrounds the making of future capacity additions, especially those of merchant plants. Siting and environmental permits, interconnection and transmission access agreements, fuel supply and its pricing, as well as financial support, must all be addressed.

NERC continues to note that, in some areas, these new generation additions, increasing 18

I energy transactions, and continued demand growth are outpacing the expansion of transmission systems.

While coal and nuclear remain the most widely used fuels in our area, most of the proposed new generation facilities will use natural gas as their primary fuel. According to the NERC report, projections show that capacity fueled by natural gas will represent over 38% of total electric generation capacity in the United States by the summer of 2008. In 1998, capacity fueled by natural gas was 23% of the total. For this reason, the adequacy and security of the natural gas supply is critically important to the reliability of electric systems nationwide. Since gas transmission pipelines do not provide much redundancy, a single pipeline failure can have widespread consequences, and as is the case with electric transmission lines, the siting of new pipelines is becoming increasingly difficult.

8. STATE ENERGY INITIATIVES AND JUDICIAL PROCEEDINGS The North Carolina General Assembly passed legislabon during the 1997 session establishing the Study Commission on the Future of Electric Service in North Carolina (Study Commission). The Study Commission was charged with examining the cost, adequacy, availability, and pricing of electric service in North Carolina to determine whether legislation was necessary to assure an adequate and reliable source of electricity and economical, fair, and equitable rates for all consumers of electricity in North Carolina.

In April 2000, the Study Commission approved its final recommendations to the 2000 Regular Session of the 1999 General Assembly.

Its recommendations included, among other things, (1) fully competitive retail electric service to all consumers in North Carolina as of January 1, 2006, and (2) recovery of reasonable potentially stranded costs by the incumbent utilities serving North Carolina.

At a meeting held on January 23, 2001, the Study Commission redirected its focus to encouraging a robust and competitive wholesale market. Consistent with that new focus, Senator Hoyle, as Co-Chair of the Study Commission, asked this Commission to review the requirements for certification of new electric generating capacity in North Carolina with a view toward streamlining the certification process for merchant plants. In response, in May 2001, the Commission issued an Order adopting Commission Rule R8-63 addressing the certification of merchant plants. This new rule significantly streamlined the certification process for new merchant plants and greatly reduced the burden on such applicants.

In another issue involving the wholesale electric generation market, the Commission initiated a proceeding on March 11, 2002, to investigate issues raised by utilities entering into wholesale power contracts at native load priority (Docket No. E-100, Sub 85A). As a condition of its merger with Florida Progress in Docket No. E-2, Sub 760, Progress had agreed to give the Commission and Public Staff 20 days' written notice prior to entering into such contracts. The parties to these dockets sharply disagreed over the extent of the Commission's jurisdiction with respect 19

to these unexecuted wholesale contracts. On July 10, 2002, the Commission issued an Order Regarding Jurisdiction concluding that it has jurisdiction and authority under State law to review, before they are signed, proposed wholesale contracts by a regulated North Carolina public utility granting native load priority to be supplied from the same plant as retail ratepayers and to take appropriate action if necessary to secure and protect reliable service to retail customers in North Carolina.

The Commission further concluded that such jurisdiction and authority "are not preempted by federal law." The Commission denied reconsideration of its order on August 20, 2002, and the case was appealed to the North Carolina Court of Appeals.

On December 11, 2003, the Court of Appeals, with one judge dissenting, issued an opinion vacating the Commission's July 10, 2002 Order. The Court held that the Commission's pre-review of the prudence of these contracts 'is clearly preempted' by the Federal Power Act and that the Commission has remedial authority under G.S. 62-42 if the provision of service under such wholesale agreements results in inadequate service to retail ratepayers. The dissent argued that federal jurisdiction over such contracts did not attach until those contracts had been executed and filed with FERC. This decision is currently on appeal to the North Carolina Supreme Court.

On July 9, 2004, Progress and the Public Staff submitted to the Commission a Joint Filing for Approval of Stipulation and Condition.

In it they point out that significant controversy and litigation have occurred with respect to the interpretation and implementation of a number of Commission imposed conditions relating to Progress' participation in the wholesale market.

In part, the Stipulation states that "Progress and the Public Staff wish to resolve the issues raised by Progress' participation in the wholesale power market so as to avoid a continuation of the current appeal, further controversary and litigation and potential future appeals."

This Stipulation is currently under consideration by the Commission.

The emergence of merchant plants, large-scale wholesale electric sales, RTOs, and the establishment of the NC Greenpower program have become important issues affecting the determination of the long range need for expansion of electric generation facilities in North Carolina. For this reason, the NC Greenpower program, merchant plants, and RTOs will be discussed separately in the next three sections of this report.

9. NC GREENPOWER NC GreenPower is an independent, nonprofit organization established to improve North Carolina's environment through voluntary contributions for the purchase of renewable energy.

It is the first statewide green energy program in the nation supported by all the state's utilities.

20

The goal of NC GreenPower is to supplement the state's existing power supply with more "green" energy - electricity generated from renewable resources like the sun, wind, and organic matter.

The program accepts financial contributions from North Carolina citizens and businesses to help offset the cost to produce green energy.

A typical contribution of $4 per month adds one block of 100 kilowatt-hours of green energy to North Carolina's power supply. Large-volume users - usually from governmental agencies or the corporate sector - may contribute towards 100 or more blocks using a different energy mix at a rate of $2.50 per block.

NC GreenPower was formed as a result of a January 2001 request by the Study Commission that the Commission investigate and make recommendations concerning the possible creation of a voluntary "green" electric generation check-off program. The Commission was requested to investigate potential benefits and costs and to recommend uses for the fund and the amount of the check-off.

On February 16, 2001, the Commission issued its Order Initiating Investigation, Requesting Comments, Scheduling Public Hearing, and Requiring Public Notice in Docket No. E-100, Sub 90. A diverse group of parties participated and filed written comments, including the State's electric suppliers, renewable energy advocates. and suppliers, and consumer representatives. In addition, a number of consumers filed written statements of position, and eleven people testified at a well-attended public hearing in Raleigh.

Based upon the Commission's investigation, it found considerable benefit in exploring implementation of a statewide voluntary green power program for North Carolina. To reach consensus on an implementation plan for North Carolina, the Advanced Energy Corporation (AEC) facilitated the organization of a Green Power Program Advisory Committee consisting of stakeholders who had shown interest in the green power program, including representatives from the utilities, renewable resource developers, environmental interests, and the State Energy Office. Simultaneously, the stakeholders began working with the Center for Resource Solutions for the purpose of developing criteria for national certification of North Carolina's green power program.

On May 31, 2002, AEC filed a proposed program plan for NC GreenPower, a statewide green pricing program for North Carolina. To assist in its consideration of this matter, the Commission requested written comments from interested persons on the proposed green power program and scheduled public hearings at several locations across the State'to receive comments from public witnesses on the proposal.

On November 22, 2002, AEC filed a revised administrative and operational plan.

As described by AEC, the revised NC GreenPower proposal included two products:

(1) a "mass-market" product to be offered primarily to residential customers that is comprised of higher-priced renewable resources and (2) a "large-volume" product to be offered to large-volume customers that is more price competitive. The revised proposal also attempted to balance the interests of all stakeholders. by narrowing the types of 21

renewable resources included in the mass-market product while incorporating a broader spectrum of resources in the lower-cost large-volume product.

On January 28, 2003, the Commission issued an Order Approving NC GreenPower. On February 11, 2003, the Commission issued an Order accepting nominations for the NC GreenPower Board of Directors and on March 11, 2003, issued an Order appointing Board members and a Chair and Vice-Chair for NC GreenPower.

NC GreenPower held its official kickoff in Raleigh and Charlotte on October 1, 2003, although the State's investor-owned utilities, as well as many municipal and cooperative electric utilities, had begun signing up consumers on July 28, 2003. As of April 2004, over 4500 electric customers had subscribed to nearly 7200 blocks of power per month in the mass market program; over 5700 blocks of power per month had been subscribed to by large volume customers. On June 16, 2004, NC GreenPower announced contracts with a number of generators to supply green energy to the North Carolina grid to meet the subscribers' demand.

10. MERCHANT PLANTS A merchant plant is a non-utility electric generating facility that is usually constructed without a native load obligation or firm long-term contract, or any other assurances that it will have a market for its power.

These generating plants are generally sited in areas where the owners see a future need for an electric generating facility, often near a natural gas pipeline, and where the owners are willing to undertake the economic risk of its construction.

Merchant power plants have become the dominant source of new power generation in many regions of the United States. According to NERC, they represent more than 90% of the capacity additions made since 1997. NERC states that, during 1997-2001, the amount of non-utility generation grew from 8.5% of total U.S. capacity in 1997 to 35.6% of the total in 2001.

In North Carolina, the certification of new electric generating plants is governed by G.S.62-110.1, which requires that anyone proposing to build a new power plant to be used directly or indirectly for the purpose of furnishing public utility service must seek and obtain a certificate of public convenience and necessity from the Commission before commencing construction, regardless of whether the party proposing to build the plant is a public utility or some other person. Before the advent of the current merchant plant generation industry, the Commission adopted a rule which governed the handling of applications for such certificates. However, that rule had been drafted with utility generating facilities and qualifying facilities in mind. There was no specific provision in that rule applicable to the certification of merchant plants. As a result, the Commission evaluated applications for a certificate for a merchant plant under a rule which was originally intended for an entirely different type of applicant.

22

The Commission issued an order in May 2001, which adopted new. Commission Rule R8-63. The new rule is specifically designed for merchant plant applications and spells out in detail the requirements for filing and obtaining approval of a merchant plant certificate application. This new rule also significantly streamlined the process which the Commission uses to decide whether to grant a certificate to such facilities.

Commission Rule R8-63 eliminated a 120-day prefiling requirement for certificate applications contained in the rule relating to utility generating plants, which facilitates prompt scheduling of hearings upon the filing of a complete application. In addition, the Commission has held hearings and decided merchant plant cases in an expeditious manner. For example, the Commission issued a final order in one merchant plant case within about three and a half months after the application was filed.

In addition, the new rule eliminated a requirement that merchant plants have a contract with a utility. Applicants for the construction of such plants are now only required to show "the need for the facility in the state and/or region, with supporting documentation."

The new rule makes all merchant plant certificates subject to certain conditions, including requirements that the applicant receive and maintain all other necessary regulatory approvals and that the certificate holder notify the Commission of any plans to sell, transfer, or assign the certificate or the facility. After adopting the new rule, the Commission has included a new condition in a number of merchant plant certificates that makes any subsequent transfer of a merchant plant certificate subject to Commission approval.

The Commission decided to begin imposing this additional condition because of its belief that it needs some continuing authority over merchant plants following certification for the purpose of ensuring proper planning and preventing market power abuses.

The Commission has also conditioned certificates issued to merchant plant applicants that needed to obtain external financing to complete construction on the applicants' obtaining the necessary financing within a designated time period in order to avoid undue delays in the construction process. In addition, the Commission has required that applicants refrain from making any attempt to exercise eminent domain authority. The Commission continues to scrutinize each application carefully and will take appropriate action in order to protect the using and consuming public.

Since the Commission's merchant plant rule took effect, certificates have been issued to Rowan Generating, an Entergy subsidiary, for a 900 MW facility in Rowan County; to GenPower Earleys, a subsidiary of GenPower, for a 528 MW facility in Hertford County; to Progress Energy Ventures for a 640 MW facility in Rowan County; to Mirant Gastonia, a subsidiary of Mirant Corporation, for a 1200 MW facility in Gaston County; to Fayetteville Generation, a subsidiary of Competitive Power Ventures Holdings, for authority to construct a 640 MW facility in Cumberland County; to Carolina Generation, another Competitive Power Ventures Holdings subsidiary, for authority to construct a 1320 MW facility in Richmond County; and to Black River 23

Energy, a subsidiary of the ElF Group, for authority to construct a 250 MW facility in Davidson County.

Due to the recent downturn in the merchant power business, several of the projects listed above have been canceled or the Commission certificate authorizing construction has lapsed. Commission Rule R8-63 provides that a certificate must be renewed if the applicant does not begin construction within two years after the order granting the certificate has been issued.

Although some merchant plants may be constructed in North Carolina, the electricity produced by these facilities will not necessarily be consumed by North Carolina customers. The owners of merchant plants are free to sell the electricity they produce to whomever will provide them with the best economic benefit, and the resulting contracts may be for short or long-term duration. As a result, the Commission has advocated the use of participant funding at the federal level in some instances to ensure that merchant plants cover the costs they impose on the transmission system.

11. FERC WHOLESALE MARKET PLATFORM AND REGIONAL TRANSMISSION ORGANIZATIONS Vertically integrated electric utilities, such as Duke and Progress, produce their own power at central generation facilities, transmit the power over long distances at high voltage from the generation facilities to load centers, and finally distribute the power over lower voltage lines for use by retail customers.

Such customers are referred to as "bundled" since all aspects of their delivered electrical service are provided by a single energy supplier. Over the past two decades, however, the federal government has pursued a policy goal of introducing, and subsequently encouraging, competition in the wholesale power market. This has led to-attempts at the federal level to remove any perceived barriers to competition, including ownership and operation of the high-voltage transmission system by vertically integrated utilities who allegedly have an incentive to stifle competition by discriminating in favor of their own generation resources.

In April 1996, the FERC issued Order Nos. 888 and 889 establishing rules governing open access to electric transmission systems by wholesale customers and establishing an Open Access Same-time Information System (OASIS).

In Order No. 888 the FERC required utilities to file standard, non-discriminatory open access transmission tariffs for wholesale customers. As part of this decision, the FERC asserted federal jurisdiction over the rates, terms and conditions of the transmission service provided to retail customers receiving unbundled service while leaving jurisdiction over the transmission component of bundled retail service subject to state control. The FERC rule also permitted recovery of legitimate, prudent, and verifiable stranded costs for wholesale service contracts.

In New York v. FERC,,535 U.S. 1 (2002), the Supreme Court of the United States upheld the FERC's decisions in Order No. 888. In Order No. 889 the FERC required utilities to separate their transmission functions and their power marketing functions applicable to 24

wholesale transactions and to obtain information about their own transmission system for their own wholesale transactions in the same manner as their competitors via an OASIS system on the Internet. The purpose of this rule was to ensure that transmission owners do not have an unfair advantage in wholesale generation markets.

In December 1999, the FERC issued a final rule in Order No. 2000 encouraging the formation of regional transmission organizations (RTOs), which are independent entities created to operate the interconnected transmission assets of multiple electric utilities on a regional basis, to reduce the cost and burden of transmitting power to more distant markets, and to further enhance wholesale competition. In that order, the FERC did not attempt to force utilities into particular regional groups but stated that it would consider any proposal for RTO formation so long as it met four minimum characteristics: (1) independence, (2) scope and regional configuration, (3) operational authority, and (4) short-term reliability.

North Carolina's investor-owned utilities, including NC Power, Duke, and Progress, were directed to file a proposal to create an RTO which would be operational by December 15, 2001, by no later than October 15, 2000.

In compliance with Order No. 2000, Duke, Progress, and SCE&G filed a proposal to form GridSouth Transco, LLC (GridSouth), a Carolinas-based RTO, with the FERC.

In March 2001, the FERC issued an order provisionally approving most of the GridSouth proposal. On April 2, 2001, Duke and Progress filed an application with this Commission requesting approval of the transfer of functional control over their electric transmission assets to GridSouth.

On July 21, 2001, the FERC entered an order calling for expedited negotiations intended to lead to the formation of four large RTOs, including a single RTO for the entire Southeast. After the issuance of this order, Duke and Progress participated in settlement discussions at the FERC with other transmission owners for the purpose of attempting to form a single RTO for the entire Southeast region. That process did not result in an agreement that would lead to the formation of such a larger RTO. On February 19, 2002, Duke and Progress filed a motion with this Commission withdrawing their GridSouth application, and on June 18, 2002, the GridSouth sponsors announced that the implementation of the project was being, postponed to "provide the sponsors time to review the effects of regulatory initiatives that are beginning now and due for completion later this year."

NC Power, as part of VEPCO, had filed with the FERC to become a member of the Alliance RTO together with other transmission owners serving areas in the Midwest.

On September 21, 2001, VEPCO filed an application with this Commission requesting approval for the transfer of functional control over its electric transmission assets to the Alliance RTO. In a series of orders beginning in 1999, the FERC approved the Alliance RTO, and in January 2001 it concluded that the Alliance proposal to create a for-profit transmission company, or transco, basically met the requirements of Order No. 2000.

On December 20, 2001, however, the FERC ruled that the public interest would best be served if the Alliance RTO were to join with the Midwest ISO to form a single, larger 25

regional entity. On January 11, 2002, VEPCO filed a motion with this Commission withdrawing its Alliance application.

In a further effort to restructure the wholesale market, the FERC issued a notice of proposed rulemaking (NOPR) on July 31, 2002, setting forth its intent to impose a standard market design (SMD) on the nation's wholesale electricity markets.

The FERC's SMD proposal would require that all transmission, including the transmission service provided to bundled retail customers of vertically-integrated utilities, be provided under a single standardized FERC-jurisdictional tariff administered by an independent FERC-jurisdictional transmission provider. In addition, it would, among other things, require the use of financial, not physical, transmission rights; auction transmission rights and manage transmission congestion through locational marginal pricing; eliminate the transmission priority of captive native load retail ratepayers who have historically paid for the system through rates; and subject many aspects of the formerly cost-based electric rates to the potential volatility of the wholesale power market.

An independent study conducted by Charles River Associates for the Southeastern Association of Regulatory Utility Commissioners (SEARUC) found little, if any, benefit for ratepayers in the Southeast from the FERC's SMD proposal. North Carolina, as well as other states in the Southeast and across the nation, filed comments objecting to the SMD NOPR, particularly the FERC's failure to adequately accommodate regional differences and its attempt to strip the states of their traditional authority to protect consumers.

On April 28, 2003, the FERC issued a White Paper setting forth its latest vision for the wholesale market based upon the comments it received in response to the SMD NOPR. Although the White Paper addressed some of the flaws in the FERC's earlier proposal, especially retail consumer protection and the need for regional flexibility in any market design plan, it nevertheless failed to resolve fundamental concerns about the FERC's vision for the direction and structure of the electric utility industry in the Southeast. For example, the FERC continues to insist on asserting jurisdiction over the terms and conditions of the transmission component of bundled retail service and advocating mandatory participation in RTOs without requiring any demonstration that such participation would be economically beneficial to consumers.

On September 12, 2003, the FERC issued a Notice of Inquiry establishing a proceeding to determine whether AEP should be exempted pursuant to Section 205(a) of PURPA from state law and commission actions in Virginia and Kentucky delaying AEP's attempt to join PJM Interconnection, LLC (PJM). On November 25, 2003, the FERC issued an order preliminarily finding that AEP should be exempted from compliance with Virginia and Kentucky law and establishing an expedited procedural schedule for a hearing and initial decision before an Administrative Law Judge (ALJ).

The Commission, Public Staff, and Attorney General intervened and actively participated in this proceeding in opposition to the proposed preemption of state authority. On March 12, 2004, the ALJ issued an Initial Decision concluding that the FERC could preempt Virginia and Kentucky state law in this case under Section 205(a) 26

of PURPA and require AEP to join PJM without receiving state approvals. On June 17, 2004, the FERC entered orders affirming the ALJ's decision with respect to Virginia and approving a settlement between AEP, Kentucky, and PJM. The Commission and other parties have filed requests for rehearing of the FERC's decision with regard to Virginia.

On April 2, 2004, NC Power filed an application with the Commission for authority to transfer operational control of its transmission facilities located in North Carolina to PJM.

PJM has been approved by the FERC as an RTO pursuant to FERC Order No. 2000. NC Power's transmission system is proposed to be integrated into PJM as PJM South. NC Power requests that the Commission grant the application on or before November 1, 2004, so that its integration into PJM could be completed by January 1, 2005, the date by which Virginia law requires each electric utility to transfer management and control of transmission assets to the equivalent of an RTO. The Commission has instituted an investigation into the application, and a hearing has been scheduled to begin on Tuesday, October 26, 2004, without opposition as to timing from NC Power.

On April 7, 2004, the Commission hosted a transmission stakeholders' meeting to facilitate a collaborative effort to identify real problems that North Carolina consumers of transmission services face and to allow North Carolina stakeholders to implement potential solutions to those specific problems without the necessity of federal intervention. Presentations and written comments were received from representatives of North Carolina's cooperative and municipal electric suppliers. Since that initial meeting, the state's transmission-owning utilities and others have met a number of times and are drafting a proposal for a collaborative approach to transmission planning in North Carolina. The Commission expects to schedule future meetings to continue this dialogue among the stakeholders and to ensure continued reliable electric service at reasonable prices for all North Carolina consumers.

12. CONCLUSION The major electric utilities serving North Carolina continue to forecast rates of load growth that are lower than they have experienced over the past 20 years. Their forecasts are relatively typical for electric utilities serving the Southeastern states.

The utilities remain dependent on coal-fired and nuclear-fueled steam generation to produce the overwhelming majority of their electric output. They are projecting reserve margins in the range typical for electric utilities serving the Southeastern states.

The current reliability assessment by NERC projects that the SERC region wilt continue to have adequate reserve margins over the next ten years, but points out that much of this projection is based on planned capacity additions that are uncommitted, undefined resources. This indicates that the utilities are planning to acquire new capacity with significantly shorter lead times, an approach typically associated with combustion 27

turbine peaking plants and purchased power. This dependence on uncommitted resources is also representative of the approach being taken by the North Carolina utilities.

As discussed in sections eight and eleven of this report, two issues relating to the ongoing authority of this Commission are currently unresolved. The first involves the Commission's authority to review, before they are signed, proposed utility contracts for the sale of power at wholesale at native load priority to be supplied from generating plants used to serve retail ratepayers. A decision on this matter is currently pending before the North Carolina Supreme Court.

The other issue is the extent of State authority over regional transmission organizations compared with that of the FERC. The resolution of these two issues will have a significant impact on the future of electric utility service in North Carolina.

Based on the analysis of all available information, the Commission concludes that the current mix of electric generation facilities, both existing and planned, plus purchased power, and the demand-side management programs now in place are adequate to meet the currently projected electric needs of the State of North Carolina.

28

Appendix 1 Page 1 of 11 STATE OF NORTH CAROLINA UTILITIES COMMISSION RALEIGH DOCKET NO. E-100, SUB 98 BEFORE THE NORTH CAROLINA UTILITIES COMMISSION In the Matter of

)

ORDER APPROVING Investigation of Integrated Resource 3

INTEGRATED RESOURCE Planning in North Carolina - 2003

)

PLANS BY THE COMMISSION: North Carolina General Statute 62-110.1(c) requires the North Carolina Utilities Commission (Commission) to "develop, publicize, and keep current an analysis of the long-range needs" for electricity in this State. This includes (1) the Commission's estimate of the probable future growth of the use of electricity; (2) the probable needed generating reserves; (3) the extent, size, mix and general location of the generating plants; (4) arrangements for pooling power to the extent not regulated by the Federal Power Commission (now the Federal Energy Regulatory Commission, or the FERC); and (5) other arrangements with other utilities and energy suppliers.

The purpose of this requirement is "to achieve maximum efficiencies for the benefit of the people of North Carolina." The statute requires the Commission to develop a plan for the future requirements for electricity for North Carolina or the area served by a utility and to consider its analysis in acting upon any petition for construction. In addition, it requires the Commission to submit annually to the Governor and to the appropriate committees of the General Assembly the following: (1) a report of its analysis and plan; (2) the progress to date in carrying out such plan; and (3) the program of the Commission for the ensuing year in connection with such plan.

Commission Rule R8-60 requires that each of the investor-owned utilities and the North Carolina Electric Membership Corporation (collectively, the utilities) furnish the Commission with an annual report that contains specific~information that is set out in subsection (c) of the Rule and provides that the Public Staff and any other intervenor may file its own report, evaluation, or comments regarding the utilities' reports. In addition, Rule R8-62(p) requires certain additional information Vbe included in the reports about the construction of transmission lines.

In its July 13, 1999 Order Adopting Least Cost Integrated Resource Plans and Clarifying Future Filing Requirements in Docket No. E-100, Sub 82, the Commission imposed additional requirements for the annual reports. Specifically; the utilities were directed to include a full response to each item of information required by the Rules; appropriate explanations for each item where the information requested is not available; and appropriate explanations referencing the location of information in the filings where

Appendix 1 Page 2 of 11 such information does not follow the same general order of presentation as contained in the Commission Rules. The Commission further ordered the utilities to adhere to the requirement that each ten-year forecast and plan consist of the ten years next succeeding the annual September 1 filing date. Also, in that order and subsequent proceedings, the Commission required the utilities to file in their annual reports a detailed explanation of the basis for, and a justification for the adequacy and appropriateness of, the level of projected reserve margins and a discussion of the adequacy of the respective utility's transmission system.

In its March 28, 2002 Order Approving Integrated Resource Plans, in Docket No. E-100, Sub 93, the Commission directed that, in order to develop a more complete list of total generation resources located in the State, the utilities provide a separate list of all non-utility electric facilities in the North Carolina portion of their control areas, including customer-owned and stand-by generating facilities, to the extent possible.

Finally, in its February 20, 2003 Order Adopting Integrated Resource Plans, in Docket No. E-100, Sub 97, the Commission ordered that all future IRP filings by the utilities should include information on levelized busbar costs for various generation technologies.

On or about September 1, 2003, the current Integrated Resource Plan (IRP) filings were made under the Commission's Rules by Carolina Power & Light Company, d/b/a Progress Energy Carolinas, Inc. (Progress), Duke Power, a division of Duke Energy Corporation (Duke), Virginia Electric and Power Company, d/b/a Dominion North Carolina Power (NC Power), and North Carolina Electric Membership Corporation (NCEMC). On December 1, 2003, the Public Staff filed its comments on the IRPs submitted by the utilities, including a discussion of reserve margin adequacy. No party formally petitioned to intervene in this proceeding.

A public hearing was held on February 2, 2004, in Raleigh, for the purpose of receiving non-expert public witness testimony. No one appeared to testify at that time.

The public hearing was then recessed until February 18, 2004, to allow for a presentation by the North Carolina Sustainable Energy Association (NCSEA) and the receipt of any additional public witness testimony.

The public hearing was reconvened as scheduled on February 18, 2004. At that time, three public witnesses provided testimony and presented material for Commission consideration. Testimony was given by Mr. Richard Harkrader, Policy Chair of NCSEA; Mr. Tim Toben, Chief Executive Officer of Carolina Green Energy, LLC, (CGE); and Mr.

Simon Rich, as an interested citizen and an investor in the wind business.

2

Appendix 1 Page 3 of 1 1 Testimony presented at the February 18, 2004, public hearing promoted a sustainable energy future for North Carolina, as well as the need to encourage more efficiency and demand-side management options. The benefits of a larger role for consumer education was also discussed. In addition, potential government sponsored funding mechanisms to help support these efforts were offered.

Much of the focus of the public hearing was on the topic of wind energy technology and the development and economics of wind resources. Related testimony was presented on the value of establishing a renewable portfolio standard (RPS), whereby utilities are required by law to provide a percentage of their generation mix from renewable energy sources within a certain period of time.

Duke filed reply comments on the public witness testimony on March 11, 2004, and Progress filed comments on March 15, 2004.

The Commission found the information presented at the February 18, 2004 public hearing helpful as it provided a timely update on the operation and economics of certain sustainable energy technologies, especially in relation to wind resources.

The Commission also understands the argument presented in regard to RPS. However, as was brought out in Mr. Toben's testimony, this is a legislative issue which is outside the authority of this Commission.

The Commission continues to support the value of having a varied mix of generation resources in North Carolina and notes that the new NC GreenPower Program is a significant step in providing citizens the opportunity to support emerging renewable energy technologies.

On March 8, 2004, NCEMC filed a revised Annual Report. Several material changes made it prudent for NCEMC to update its September 2003 filing. One major change is that four of the 26 Member cooperatives of NCEMC have provided notice that they will be responsible for planning and acquiring all future power supply to meet their load obligations.

The information contained in the revised NCEMC filing has been incorporated into this Order.

COMPLIANCE WITH FILING REQUIREMENTS The Public Staff comments contained a review of the utilities'- responses to information requirements contained in Rules R8-60(c) and R8-62(p). According to the Public Staff, the utilities responded to all subsections.

3

Appendix 1 Page 4 of 11 PEAK AND ENERGY FORECASTS The Public Staff noted that all of the utilities continue to use accepted econometric and end-use analytical models to forecast their peak and energy needs. As with any forecasting methodology, there is a degree of uncertainty associated with these models that rely, in part, on assumptions that certain historical trends or relationships will continue in the future.

The following table summarizes the 2004-2013 growth rates for the utilities' system peak loads and annual energy sales.

2004 - 2013 Annual Growth Rates Summer Average Winter Energy Peak' Summer Peak Peak Sales MW Growth Progress 1.9%

216 1.9%

1.7%

Duke 1.7%

309 1.2%

1.6%

NC Power 1.8%

305 1.5%

1.9%

NCEMC2 2.2%

59 2.2%

2.2%

The loss of native wholesale loads, and a decline in the industrial segment, have contributed to somewhat lower energy sales growth forecasts for Progress and Duke.

NC Power was the only utility that showed an increase in the growth rate of its summer peak.

DEMAND-SIDE MANAGEMENT (DSM) OPTIONS The Public Staff has continued to point out that the utilities' emphasis on DSM programs has waned since the mid -1990's. As in recent past proceedings, the Public Staff again recommends that the Commission continue to monitor and evaluate the appropriateness of the utilities' DSM efforts.

G.S. 62-2(3a) provides that it is the policy of this State "[t]o assure that resources necessary to meet future growth through the provision of adequate, reliable utility service include use of the entire spectrum of dem and-side options..."And "[tjo that end, to require "All of the utilities consider their summer peak to be the annual system peak.

2 Includes the 22 Participating Members 4

Appendix 1 Page 5 of 11 energy planning and fixing of rates in a manner to result in the least cost mix of generation and demand-reduction measures...

According to the Public Staff, each of the utilities complied with the letter of Rule R8-60(c)(9), by providing a list of current DSM programs. The Public Staff noted, however, that only the utility programs designated as DSM resources in the 2002 IRP reports were included in the 2003 IRP annual reports. None of the utilities' filings listed any planned programs, new programs under consideration, or modifications to existing programs.

Proiected DSM as Percent of Total System Peak Requirements Progress Duke NC Power NCEMC Summer 2004 3.3%

4.4%

0.2%

8.8%

Winter 2004 4.8%

2.6%

0.2%

7.5%

Summer 2013 2.9%

3.5%

0.2%

7.4%

Winter 2013 4.4%

2.3%

0.2%

6.2%

RESERVE MARGINS Reserve margins shown in the current IRP filings are comparable to those submitted in the last proceeding. For the planning period 2004 to 2013, the range of summer reserve margins reported by the utilities remains below 20%.

For this period, the planned reserves are: Progress, 14% to 17%; Duke, 17%; NC Power, 12.5%; and NCEMC, 0%.

NCEMC assumes all capacity purchases will be 100% firm with reserves provided by the supplying entity.

The Public Staff stated that in the 1970's and 1980's it was necessary to use a minimum 20% planning reserve margin target due to the size of the baseload powerplants (coal and nuclear) relative to the size of utility systems they served, and the high rate and duration of forced and scheduled outages during that period, particularly for nuclear plants.

The Public Staff noted that today, however, those same nuclear plants are operating with very low forced outage rates and short refueling outages, and the large baseload generating units are responsible for meeting a significantly smaller portion of the system peak demand. Thus, the use of lower reserve margins may be justified.

According to the Public Staff, North Carolina utilities recorded peak loads at an all-time high in the summers of 1999,2000,2001, and 2002, resulting in weekly operating 5

4

Appendix 1 Page 6 of 11 reserve margins that were often near five percent. The Public Staff believes five percent to be, at best, a minimally acceptable operating reserve margin. For these utilities' summer peak loads, such a reserve margin would range from 600 to 900 MWs, approximately equal to the capacity of each respective utility's smallest nuclear unit.

Because of the decline in actual summer operating reserve margins and planned reserve margins reported to the Commission in Docket No. E-100, Sub 82, the Public Staff filed Comments on December 3, 1998, contending that the issue of declining reserve margins required further explanation by the utilities. On July 19, 1999, the Commission ordered the utilities to file a detailed justification for the adequacy and appropriateness of the level of the projected reserve margin in their annual filings due on September 1st of each year. The utilities responded to this continuing requirement in their 2003 filings.

The Public Staff provided the following comments related to the utilities' responses:

1.

Progress provided an assessment of the adequacy and appropriateness of its level of projected reserves, indicating that the reserve margin range of 14% to 17% for this period was adequate. Progress found that the industry's widely used Aone day in ten years_ Loss-of-Load Expectation (LOLE) criteria would be satisfied by its filed reserve margins for the planning period.

Progress used computer modeling, its own studies, and assessment of capacity assistance from neighboring electric systems to evaluate the reliability criteria.

2.

Duke responded that its reserve margin target of 17% was supported by the increased availability of existing generation, shorter lead times for new generation, and the emergence of new purchased power options. Duke's operating experience was also factored into the selection of this 17%

reserve margin.

3.

NC Power reported that its target reserve margin is 12.5%. NC Power's planning reserves in the past were established using a 12-hour loss of load criterion. In 1999, NC Power initiated a review of this reserve-planning criterion to evaluate its appropriateness.

An executive committee determined that a target reserve margin of 12.5% would be adequate to cover various contingencies.

4.

NCEMC did not provide an assessment of the adequacy of its reserve margin.

NCEMC stated that all purchases include reserves, and future purchases will include reserves or NCEMC will acquire them independently.

6

Appendix 1 Page 7 of 11 According to the Public Staff, Progress, Duke, and NC Power appear to meet their projected reserve margin targets for the planning period. The Public Staff recommends that Progress, Duke, and NC Power maintain their reserve margins as filed.

TRANSMISSION ADEQUACY The March 28, 2002 Commission Order Approving Integrated Resource Plans required that future IRP filings by all utilities shall include a discussion of their respective utility's transmission system (161 kV and above). The Commission also required that the utilities shall meet with the Public Staff within 30 days of the filing date of their annual reports to discuss detailed information concerning their transmission system.

The Public Staff indicated that the companies included in their annual report filings, in addition to the data required by Rule R8-60, discussions of the adequacy of their transmission systems and copies' of their most recently completed FERC Form 715 including all attachments and exhibits. The companies also met with the Public Staff within 30 days following the filing date of the annual report to discuss detailed information concerning their transmission line inter-tie capabilities, transmission line loading constraints, and planned new construction and upgrades, within their respective control areas, for the planning period under consideration.

NON-UTILITY GENERATION FACILITIES In its March 2002 and February 2003 Orders Approving Integrated Resource Plans, the Commission requested that the utilities provide a separate list of all non-utility electric facilities in the North Carolina portion of their control areas, including customer-owned and stand-by generating facilities, to the extent possible.

All utilities complied with this request in their 2003 reports.

BUSBAR INFORMATION In its February 20, 2003 Order, the Commission directed Progress, Duke and NC Pow er to include information on levelized busbar costs for various generation technologies in their September 1, 2003 filings. The Public Staff commented that Progress and Duke complied, including this information in their respective filings, but that NC Power did not.

The Public Staff recommended that the Commission direct NC Power to provide this information within 30 days of the Commission's order on this matter.

In fact, NC Power did include a small section titled "Levelized 'Busbar' Costs" in its report. However, the section only covered baseload coal, combined cycle gas, and combustion turbine gas technologies as alternatives. Other alternatives that did not pass NC Power's initial screening criteria were not included in its report.

7

Appendix 1 Page 8 of 11 CONCLUSIONS Peak and Enerav Forecasts The Commission finds that the utilities used accepted econometric and end-use analytical models to forecast their peak and energy needs.

Demand-Side Management (DSM) Options The Commission again reaffirms the value of cost-effective DSM programs, and concludes that it should continue to encourage the appropriate application of DSM options to the total resource mix of each utility.

Reserve Margins The Commission continues to recognize that the electric power industry remains in the midst of an economic and regulatory transition and that the resulting changes and uncertainty have led to the rethinking of certain long-accepted industry standards. As a result of these changes, as well as the information contained in the present record, the Commission does not believe that it is appropriate to mandate a particular reserve margin for any jurisdictional electric utility at this time. The Commission concludes that it remains more prudent to continue to monitor the situation closely, to allow all parties the opportunity to address this issue in future filings with the Commission, and to consider this matter further in subsequent integrated resource planning proceedings. The Commission believes that existing generation resources are adequate in light of current conditions. The Commission does, however, want the record to clearly indicate that providing adequate service continues to remain a fundamental obligation imposed upon all jurisdictional electric utilities, that it will be actively monitoring the adequacy of existing electric utility reserve margins, and that it will take appropriate action in the event that any reliability problems develop.

The Commission concludes that future IRP filings by all utilities should continue to include a detailed explanation of the basis for, and a justification for the adequacy and appropriateness of, the level of the respective utility's projected reserve margins.

Transmission Adequacv The Commission notes the ongoing discussions between the companies and Public Staff relating to transmission adequacy. Each Utility again provided a copy of their most recently completed FERC Form 715 in their annual report filings, including attachments and exhibits, and met with the Public Staff within 30 days of the filing date of their annual 8

Appendix 1 Page 9 of 1 1 report to discuss various transmission related issues. The Commission supports this continuing dialogue between the companies and the Public Staff.

The Commission further concludes that future IRP filings by all utilities should continue to include a discussion of the adequacy of the respective utility's transmission system (161 kV and above), as well as a copy of the most recently completed FERC Form 715, including all attachments and exhibits.

Non-Utility Generation Facilities The Commission finds that all utilities included a separate list of non-utility electric facilities in their 2003 annual reports, and that each utility should continue to provide this information in future reports.

Busbar Information The reports of Progress, Duke, and NC Power each included sections addressing levelized busbar costs. Progress had included this type of information in previous annual reports. In its 2003 Annual Resource Plan, Progress examined a large sample of technologies including conventional, advanced, and renewable energy resources. Duke's report also contained an extensive list of technologies. Its analysis divided the various supply-side technologies into groupings of conventional, demonstrated, and emerging. As previously noted, NC Power listed only three busbar alternatives in its report. Other types of generation were not included because they failed to pass NC Power's initial screening process.

The Commission finds value in this type of information as it helps in understanding the screening process used by the utilities. While the Commission does not see an immediate need for NC Power to submit a revised, more detailed response on levelized busbar costs for inclusion in its 2003 Annual Report, the Commission does direct NC Power to expand its analysis of various generation alternatives for inclusion in its 2004 report to include also those that have not passed NC Power's initial screening criteria.

Approval of IRPs As stated in previous IRP dockets, the Commission is of the opinion that the IRP review is intended to ensure that each utility is generally including all of the considerations required by the Commission's Rules in its planning process; that each utility is generally utilizing state-of-the-art techniques for its forecasting and planning activities; and that each utility has developed a reasonable analysis of its long-range needs for expansion of generation capacity. Also, the Commission reiterates its opinion that evaluations of individual DSM programs, certificates to construct new generating plants or transmission lines, and individual purchased power contracts should be handled in separate dockets 9

Appendix 1 Page 10 of 11 from the IRP proceeding. Consistent with this view, it should be emphasized that inclusion of a DSM program, proposed new generating station, proposed new transmission line or purchased power contract in a utility's IRP filing does not constitute approval of such individual elements even if the IRP itself is approved.

The Commission concludes that the current IRPs should be approved. No party has argued that the IRP filed by any utility should be rejected.

IT IS, THEREFORE, ORDERED as follows:

N

1.

That this Order shall be adopted as a part of the Commission's current analysis and plan for the expansion of facilities to meet'the future requirements for electricity for North Carolina pursuant to G.S.62-110.1(c);

2.

That the Integrated Resource Plans filed by Progress, Duke, NC Power, and NCEMC in this proceeding are hereby approved as hereinabove discussed;

3.

That future IRP filings by all utilities shall continue to include a detailed explanation of the basis and justification for the adequacy and appropriateness of the level of the respective utility's projected reserve margins;

4.

That future IRP filings by all utilities shall continue to include a discussion of the adequacy of the respective utility's transmission system (161 kV and above). In addition, each utility shall include a copy of the most recently completed FERC Form 715, including all its attachments and exhibits;

5.

That the utilities shall meet with the Public Staff within 30 days of the filing date of future annual reports to discuss detailed information concerning their transmission line inter-tie capabilities, transmission line loading constraints, and planned new construction and upgrades within their respective control areas for the planning period under consideration;

6.

That future IRP filings by all utilities shall continue to provide a separate updated list of all non-utility electric generating facilities in the North Carolina portion of their control areas, including customer-owned and stand-by generating facilities, to the extent possible. This information should include facility name, primary fuel type, capacity and location, and should indicate which facilities are included as part of their total supply resources; and

7.

That future IRP filings by Progress, Duke and NC Power shall include information on levelized busbar costs for various conventional, demonstrated, and emerging generation technologies. Any claim of confidentiality under the North Carolina Public Records Act shall be set forth with specificity at the time this information is filed and 10

Appendix 1 Page 11 of 11 shall conform to each of the conditions specified in G.S. 132-1.2. In addition, a redacted, non-confidential version of the information in question shall also be included in the annual report filings.

ISSUED BY ORDER OF THE COMMISSION.

This the 23" day of March, 2004.

NORTH CAROLINA UTILITIES COMMISSION Ail LT1Owc&

Gail L. Mount, Deputy Clerk mrO32204.01 11

APPENDIX 2 PAGE I- ;-OF 2 Table l-i Proge Eeirg ':roihas Seplt ber2103 NC0(amr),

4 GENERA7IONADDmONS BnParMsw UPr fRm6nd CT UWdsgtnated Capacty p)

Z204 Z22-2M 200 Iwo 2

20 10l 201Mt 2iZ 2013 47 24 155 800 432 432 150 6O0 lNSrALLED GENE P471CW Cambustion tubine Combined CyCle -

Fossfli Hydra Ulasignated Caacy Pl)

RONASES & OERS~OU'Cs NUMG Cogm NUG:Qualting Fodk A5ltkort2 road RhirCT PE-AK DSMANDI Rgtail Wholesale

$YSM PE LOAD Firm Sales Large Load Callment V~ijtte Redionx TOTiAL LOAD ESER iYES (2)

Cap q

ciyiagnX Aav1gn

/4)

2975-2975 2,975 2,975 3,130 3;130:

.3.130 3.130 3130 3.130 556 55S 856 556 W5 55 5

5 556 5,25 5,285 5,285 5,285 S,285.

5.285

'28 5,285 628 5,2B5 18 218 218 tE 218.

218 218 21 218 218 410 3,434 3,434 3,484 34:4 3

,434 3,434 34 3,434 3,434 300 7I2 1,164 1.314 1.814 64 84 64 64 64 64 64 64, 84 64 257 257 257 S8 98 98 98 98 s9 68 61 61:

1i t 16 5

t5 250 250 25D 250 25D 13;848 13,872 13,527 168 13,23:

14,116 14,23 142 14,571 15,341 43 8,518 8805 LOSS S,7 t,379 S586 S,791 6,983 10,178 11,296 11.44.

11,875 101 209 13 42.2 12 5

13,0l8 143,2 1W4 11,904 11,775 55, 12,552 1s7 13.018 1

17 317 17 317 217 31 37 317:

317 317 121 12,37 12.149 1.275

¶2487

.12.738!

12942 13,177 13401 13,627 2,002 1,878 2,052 8

1,714 1,7i57 1.27 1926 1,853 2

.98 14%

1%

j%

1;3%

12 2%

12%

¶3%

t4

.-17%

16%

1-7%

141%

144%

158%

14%

15%

ANNlALSYSEbM ENERGY ('GM)

S0SUN,109 5

648 46S 65,16 6,7

6.

68.&f0 69.90 wtotal S

1) Foranndn purposes only toes not IWoata emnftmnt totype, amcwf orewnraIlp

2) e4wsvs Totat Supply Resouww Flm

3) maly Margin JemsrV I1w! Supy Re e1

4) Reseve M~arin " Reserves Fir Oblgaions

5) Revse129103 to hicludenal Sysem eErgxyh foti.

APPENDIX 2 PAGE2 OF 2 Table 1-2 Press Ergy: Colinas Spteme2DJNC Jcore ;P~lan Filng (Wmer 3

04m05 050

.0610J

.07108 081 f9g10 11 1112=

12113 GENERA7TONADDMONS Brunsvick NP Uprate Richmond CT Undesignated Capadty (1) 47 24 180 372 5Ml 552 i86 INSTALLED GEJEWTI0o Cofiusbuon Turbine Combined Cycle Fdssg ti Kdro Undestgnated Ca Pa

()

3,.74 64:

6.3:69 16:

3.3863

,474 648 216 3.430 PURCHASESt d oaER RESOukcSs SEPA 4

84 NtGegn 323

.259i N4UC3 utailfyng FaciliTy 58 55 tRoport 2

25 250 Broad Rer C S

TOTAL SU"PR U

E 3f 14,i13 3.474 648

,5,369

'215 344 64

259 13

'250 15s2 114,5:2 3, 474 3,474 I648 648 o5,369.

6,36i9 21:6 216:

,454 3.44

.,654 648 0,369 216 3,454:

3;,654 5,359 216

• 45 372 648; 648 5,369

+5,369 2t16 21:6 3,4-4

'3,454 924 1,476 3,654 648 5.359 216.

I31454 1,662.

64 O8:

15,980 64 64 64 100 '

100 100

13 I3 5

2!5iD 250 250 44 14,3 14,:0 14,433.

114,433 1.4,60 664 4

100 100 64 100 5

64 Mg45 147 15 i t15,26 PEAK DEMA N Retail Wholesale

$YS7EMPEAgLAD Firm Sales -

aLvae load Cutalment V~olage Reduction

$OTAL LOAD C~paclty Margin (8 Reserve Margin (4) 7,566 7,761 ZQ.

2M_

=k 10,1B7 10.300 10717 10,8560 317 317 11,08 11343 3,913 3,763 37%

35%

-7..921 10,507T 10,607

-317

180 11,104 3,985 t 27%

38%,o 8.90 I 8,444 8,626 10,711 10,898 11,123 11,306 ii-as I* i-, -

1i,3tPS 317 317 317 3117 "18_4 17 1f,1 11,402 41j632 11,818

• .81A 8.985 9.161 208 2.-731 2.758 11,516 11,716 11,919 SJ 317 317 MM03 12238 1.4 3.756; 4*110 4,0610

25%

2MI 25%

33%

'35%

84%

3.722 26%

35%

3.4 635 3482 3416 24%

24%

23%

12%W 31%f 30%9 IHoles:.

S1) o pan

&o doespo t Indite mmitet'l anou twership.

2) Reserves n

Tbtal SuipplyRes rces Firm IOb9lallons

3) Capacty*Margin- 'Retervs lTotal Supply Resources

• 100.

-4. Reservelrm w Reserves PhFnn Obugatioht 1

S^tonl Prh*CtlDns of Ltmd, Capacity, -and Resreig for Duks Pbwor 2003 Annual Plan, aoe Cnse:

W = W1HETR. S a SUMMER I Duk Ssterel Cumduaivae Sysiem CapeOt 2 AvOIabteO Giie P

C#Po 3 CAp d

4 pm 5 Avabla G

Copef S Cumwiob*

Pmd*"Oae e

C

'6t NO7.

V oummjk.. s~nwI 1 Cunilav eR.

t Bas LX0da f g

servoes Wf 7SDm 1g0

eetn Rhve 11 % hasew^a9*

fsr6 DSM:

13

. u49a

Sudl, 14 Cumiativ Equ*ntCaac Rse~eWsTWiDSM; 15' Eqdsent

'i 16 :S%716fl gi~

17 % CactP*:M~q

.
v_

¶674

-17,3 15.0 16,321 2301 1-i433 2,309 1.533 8

0,39

-19 20,359 12.30

.583 687E 72?

66 oL 07 0

485 o

50 0o 05 2.0,62 2020 21ei036-20.84 6.145

.30

,0986 2120.

327%

12.2 31.9%i t2,7%

24.5%\\ 10%

724.2%

i112%

.410 798 410 78 21,302 2P6

`2p1.446 21.429 5,UJ5 2,999 5.498 3,108 2.1%

14,5 25.8 14 W

8 S

050

~2D09 W6 7 2007 0710

-2008

.B~

0610 200 180,5?.

4B,442 16,250 t8,7 1.441 19,095 18,632 193 20,309 1,41 20242 19.6 0.42 19.486

'i0.154s 1922 (60)

(7 0

0 0

(81 (153) 0 20249i i,48 0.242 i gBt,4 2024.2 1.`70 20.001 190t5

-47 4290 46 27 27 i1t 24 t17-O 0

0 0o j

091 900 900 1,4S0 1,450 2.079 207S 2,7°

'21168 2.95 21,602 21.1 21, 1,0 22 2,2061 5.109 21353 5,352 2.415 5,528 2,474 8,565 2,528

,~6 12.5%

325 129 35.6%

130 53.5 13 409 779 408 77r 407 78 407 758 21575

.57 21.957 122376 22,334 267 22,810 5.518:

3 1t2 5.760 3,iR

.S935 3,239 5#75 3.381 334%'

.0%

3A 17.0*

361%

'17.0 35.9%

17.4%

256%

14.5%s 28.2%

14.5%

85%

14.%

264 14.6%

w S W

.09110 27010 10/Il 15.51 15.765 20,001 10,225 tO.001 10.117 124 117 0

0 2.79 3S205 0f 0

22.844 22.439 G,0 2,674

'35.8%

13.5%i 26A%

11.9%

408 752 23,250.

23.191 6,432 3.426 3,2%

17.3A 27.7%

14.9%

1i00 19,893 (85) 19,808 124 3.205 23,tAt 6s,128 28.5%

• 406 23.543 6.534 38.4%

27.8%

Ssa~on$Pnao cfo~iuof Lo ad parityn md R.erves far DruPj# *Piwr20b3 Anntal Plsa BRss C*se W10 INT.IA, S. S1J4I1 It Duke StianP.ik C$11e fty CwPp*1 2 AVSI abI Gg 4

~

lefl4 S4 CwvmXAsvW" COP" 0: Cudaid3leioFnlua.le 8 uwe1I

.uur

w.

Atior..

10 G9&amgR 12 %CWMrgn 14:

untIM.e Squlht C*p~ae1 ht5,rR, wDilre 12 % 1ap7g M*r~k, 2011 1t1*12 12 12J1.

A2013 i1314 201

ti.

2018 15*16 2018 th 2017 1710 :

2016 4o1 7.W

0 7-

.47 i

o, 213.762 5

17*

21.098

.805 d1.42 1004 2i,7.4 i0i96 220 4;39 i2.445 i903 woes it3zf

1. 8.01 1642 19,710 1t.042 1t0,18 184942 19,7t 1t 942 19;718 I0t942 19.716 18,04 0.

099 o

':

C 6

o d

0 tt o

o o

9 o

MO.W32 tMom t0.0 l.tt, 1.942 1716 132

.94 178

,42 1"a U1i.942 ST,718 16.S42 11 i21 11 121 fi4 i2 26 23, 23 23 23 23 23 23 23 O

1t 0

0ff

o O

1)

O 0

O 0

O 0f e

3,.691.t 4,I 4.01s6 4.,615 4^4, 4+1 4.53 s !

s.4 6.409 6.73 5,703 5.29 6-S,219 6,603 232 23.191 23.854

• .563

• 4241 3

2.51 24,724 4q1 25.2?f 24735$

25,3 254 2.02 25,596 42,7

,413.

2lt IS.441 2,704 0.07 IA5S3 a 00

7. 26 3,00 7,28 3.144 7,22 3,123 13i:

37.3%

13.4 370%

13.4%

37.7 136%

39.

140%

40.0%

13.6%

40.5%

4;2j%

M414% 139%

12.%

27.%

11.5%I 270%

1

'.8%

• 7,4%

tIJt 28.:

ti3%

26.6%

12.1%

25.7%

2.5%

29 12.2%

45 6

74 45 73 44720 403 t71t 402 t1

.23.5t 24,025 23V901 24,2$9 24.217 24.e4:

24,801 25.12k 25.151 2$.80 25,47 2$,437 25.960 25,422 28219 3.484 8.518 3.47t 6,5; 3.525 7.04¶ 3,53 7,21 3.7#

7,600 3,7O 1,741 3a,60 8.024 3.8j4 t.3%

39%

1%

3%

174%

i4.%O 4.%

42S%

1%

42.t%

17.;5%

43%

17.14%

j48%

26; 14.5%

2t2%l 145 268 1

2§.1%

14.%

29.7%

t4.6%

29.%

14.9%

V04%

14,0%

• 0,

t.z (h 6x

APPENbIZ3

-APPEJI3 PAGE 3 op 5 ASSUMPTIONS-OF LOADCAPACITY, AND RESERES TLE The 4otiowrng notesae numbered ttnh e nhe tSES ONMAl.

l E

NS OF LOAD. CAPACITY. *AK RESERViFS tabneAl vahuhs ae MWxxceptwherwatiownas a Percnt

1. Planning Iidone for-h. peaa deand forlhe DultrSystemlndudlngnt~ahtatla. Nertahatls became a Ddiviton ofeule P er gs?. 31998.

2. GeneraidnS Capacit ttwstbe oti bygune 1 beijncuded In tetevallabe apactyoe f

reme

-p8ak t Capai

. t epacity for lh ewtb raica Or tha yeer. Incudes.10M UNahn.alitn tydo capacity, tand tpial cWapaciy fr C~atia~.~ NuclearStation less 400 M1W to contfr NOMA1 urnt capacit sale, a nd thej MiDl Ceeik Cmbstin Turbine aciltywhch has

anet SirumWr Rating at 573 MW.

3. Capacity Additins rfet.$

7.t5 MW capact uprat onX te arsaalsflya ro Unit.

4. me6tMW~cltyrtnentr*in2006rpresents lti. projctd rtsefmertt d~a lta f ts at IvRbend..

The 88MW apact riret 008 Teprns the po oe rtre e br4 :

RooitWsfingouse).

Tieh.

-0 apaelty9re"ireitn200m9represetsterS eedretemnt dt for 2-a at Alveud.

Theo 93MW apaity eIeent200 repree h pojectbd reftrmentdate f stings a B The 108 MWC pactteterm6:nt n0 represents the prQX$ededrtiremet date for CT's St Butrd Roost(General EleCtic).

Thii 5 MWc alty rieentI 2011 repenshe pjeidletirementidate*rCts a: Dan Rker.

The 9.MW Iapait etir nt. i 3 repreniis prp2ected temedate or CTjat Lee.

On Mlay2300. thNR iuedo rewe t opeti liC rks i n

ucearut at one. IDuke now has thotion I6 0

4'o coeunts t-an lo t

ar 203. i evaltenonn ngona the biity d_ opeingp the year203.

i respect capadty Th Stil Inte pan, m

ectinS tlAnual lanor-Jflhrdatlto

'Ihe tydr faci~ies forich uke hias submitted in spplicaiotoPRQJ for licence reneal are assumied to ontinue operationtrough t*>o.paning horzn. ace Si tion 6of Annual la for furter detail All -retireent dates ar subet t evieiw orn en ongong basis.

6. Culi tse tathav vlomponnty A Elfedlie Janaryi.

ft SVA iEPA atlocatIoa'i asrlced iS Wi

.irec setfsaiduoing bySaneca racowood.

Salua RliverN MO. dNI>PAI.

he 94 MW!reUI ctsaltoatonslabrPMPAnd Schedule l0AcustomemsvXoContinucto

8. Pidot Muiia oe guncyhs gle o;ct hywit4ibe ey reosiblb for totu load requirements e hinnjn Januay

t.

tis educes e:A allation to 181s i 2006, Which is attbuted t30 Shdule tOA customer ih cot tobe s e by. Duke, C

pFaslstesnehrs t

MW Cherpe Couty ogenarauin Parcontrad wch beganJune 1998 and epresJune 20f3, VheMW lm i purcasei conract w fth I

ran ol Energy wfineri signed Fairuary 2000 ndt expires Feray205 n msscularneous other OFprojects tot:ll.ng 20MW

The R fyods Cntractfr 52MW whchepiresDecbr1. 201ant nlded in line £,'CuntuatvePuchase onrats

0. Purchase p151 MW*mRwn Cou n~ty Poiier. LLCUit2bega~n Jne2001 and xes ticm'.:2

, 005.

E. Purchase 07 152 MW from owan County owr, :lLC, UnIt I begantJune 1.2002 und wrtresMayt31, 2D07..

F. Puts -of 153 M~rmRwan Coutyowr. L, U

$ nltll biegtin June 1. 2004 an exspires Uay :31, 200E8.-

'6. Prchs of600 MWroR&kn Poer, LLC. began Juy 0

a pirs Deeber1,200.

Sr future Resure dtions represe a.cmintio hnew cpaltraS a, s og4ern capacity ptrchaest o*o ft holeslemret cityurapbi iocr aeswihebeing considerd.

I Neithere date of eio;

, thete atresource, contra eismi.J

• pl~i purcasd powerfelects annual prases bu may vary In lngt base up~on m.

arket codtin r syetem nieed..A4l Future Resource Adtons a n unmittd id representcaaity re*ied to aitauin h at Plann resere mrgn.

• 1

.11..Reserve hrargtnl~s Bhoiw *r beeec only.

Resjerve:Matgm.(Cumutativ apacItySsem Pf eak DemsndVstemw Peak Demn 12^ Caaciy rgn is t~iendustry standr term -A 14.8 apercent enapat'rin is equivalent too 8 7i0 ;percent reservedmargin ai aa Ca y sten Peak D ein at Copacity l

1S. CuwrlelaiveDemsnd~l Managment capacity represents the deind-side mnanagement conributon toward

• etn IliC load prpgrarnm reflected kith ese nubes n; icknte interuptile Demand Side Mlanagemenet programs sr.

to* aaed dn ityproblem u PSf

APPENDIX 3 PAGE 4 OF'S YEARu 3 SUMMER WINTE

.M Y

W 5 ENIERGYt (GWII) 2084 17,997 577 96,20 2005 18,321 1948 97,299 2006 1842:607 98,589

.2007 18M770 162 100,084 20l09 1.9,433 1663 103,492 2011 2 0,101:

17X009_

1_,5 2012 2:430 172107 10)8519 2013 20,762 17,407 11O42 2014 21,098 1760 112054 1015 21,426 17,80 113771 2016 278004 115,8 2017 2210 18,196 11 2018 22,445.

18, 11i9,411 ote 1This -f i Xoej thpe same as the ne inclu in he 2003 Due wer rc bat rpt ud t

NCEMC, SR anId NC supplemental lou b

retaifned twnearsp and onda 20 at reportainins the MP supplementl loadabovertae ownership. See pa 0ge 30 of the 2003, Duke P er For al detils Note 2: Theeimpact,Oi' energ -efficiency S progas i5 acc fri the load forecast Note 3. N1CPAI has entered into.a firm csale whereby tey sold 40 MW -of their ownership poin of:the CN ion beginniJan y 1, 2003. This change will reduce the fore ast of Dukes l bigon and t avalableapatyto meet the'load iga O Theltn assumes the reductions temaMnver the 15 ye lannig zonl.

'Note4: Summer ptea dem is ifrthe calendar yeasnndicated andincludsa -portion ofthe demand of the other joint owers of te Catawba 1cle tation (S).

Supplementa load

vertaind owes-for NCEMC, SR-and NCM:

i notincluded. Ao, beginng oJanua 1,

6 supplemental load above the PPA retained ownership is not included.

Note5:Wtiter ekdemand includes a orionofthe dmandof~ther other joint owners of'the CNS.

S lena oad abovetanedw rhi for Mn, S

d NCMPI is not included. Also, beginning on JanuAty 1, 2006 supplemental load boehe PPA re d ownership is not included.

APPEND1X 3 PAGES4 OF 5 Note 6: Teritorial energy i's the total projected energy needs of the Duke service area, including losses and unbilled sales (adjustments made to create caendar billed sales £rotm billig period sales), and the energy requirements Of the other joint owners of the CN.

Energt above NCEMC, SR and N:MPA1 ownership is not included. Al bi lon January 1, 2006, energy above MPA xetained ershp is not inued.

Rule Ref-6 AnlUal Roport Item (1)

Base Fotast (1)

OSdj frograms (2 Adjuste-d Loads (3)

Totl Matfalled Capabifl y (4)

Unit Adjustmen'ts Hydo (O.)

Firm Purehasht (8)

Future capacity(

Market Total Summinier Capacity Generatin Resetrye Reserv Mlergn () (8)

CapacityS Margin

'Energy Fo~racast (*

Dominion North C roain, Power 2004 SUMMER GENEtN CAPABILT

-PEAK LOAD'S REERVE MARGIN, AND ENRGY FORECAST BASEON 2003 BUDGm T (IN MW)

I 20004 2005 200 207 2008 2009 2010 211 2012 2013 16870 16935 17255 17578 17907 18221 18526 18836 19148 19417 38 43 46

-34

-34 35

-36 48

-38

-38 1$032 16898 17219 17544 17873 1818 184901 18798 1,110 19379 15255' 152 109 15419 1538 1590 15417 15417 15417 15417 27 30:6 27

3288, 27 3112 27 309

.27 289'1 27 2890 2890 2890 2887 2887 422 433 23 1193 1827 2152 2494 2801 3114 3497 18710Q 19010 190371 19737 20108 20459 20801 21147 21498 21801 27 2112 2 21 219 223 22731 31 239 2388 2422 12s 1245 II2.S 12.6 12i5 12.5 12.8 12.5 12.5 12.5 1h1

i.

11. 1 111:11 11.1 1.1, 1:1^.1

':1 11.1 11.1il 1'1.:1 m 8765 90898 21O74; 3733 95216 96932 95656 100Q61 102284 m 2f r t

Rule RO-60 Annult Report Item (1)

Dominion North Carbliine Power 004 WIlI GENERATIN AABIPEAI OD, RESti$E MARGIN AN ENERGta FORUCOT BASED ON2003 BU:GTCAS k

(IN: MW J.

PBase Foraaast (1)

DSM Progit (rt AdJustr Loads (3)

Total lnstalled CaPabillty4 UnitAdluatmentse Hydro (6)

Firm-Purchass(6J Equre Capacity (7)

Maokt Total Winter Capacity 204 0056 200D 200?

16016 15146 10400 1s661 15829 43

-3

-30

-29 9

14952 1:5113 15370 52 15800 1573 15753 15780 15807 15834 2009 2010 2011 2012 2013 16095 16359 1003 16045 17028

-30 430

-30'

-31 2

16085 129 16573 16814 1,696 16801 16012 18166 18155 16185 0

3848, 3610 27 27 3428 3413 27 3320

27 3205 3205 3205 3202 3202 O

O

0 O0 0,0 19401 19390 19235 1947-19181 o

a 0

0 0

19093 19360i 19360 19367 19357.

Generattng Reserves Resre Mar'in (%) (8)

CEafpacit lartln (%)

Eneg Forcast (9) 4419-29.,

22.8, 4277

28.3 22.1' I20.1 t.2 sS

3&25:

23.2 IA;0 3381 21A4 17.6 3028 18.8 1.9:

3031 18.0 2787 16:8 14 2843 18.1 13.1 2361 1:3:.

112.

87652 8875 90598.

92174 93733 95216 9WM3 98656 10p061 102284 rnrg

,0 to i6

APPENDIX 4 APPENDIX 4 PAGE 3 pF3 NOTES::

1) The Base Forecast is developed through Dominion North Carolina Power Is calculation of: results f rom models that review projected peAk loads, area output and energy sales.

included in this review are calculations of projected sales to residential, commercial, industrial, resale, public authority, and street and traffic lighting customers.

2) The DSI4 Program calculations repres-ent the projected net effect of the Company s vari ous demand-side programs.

3) The Adjusted :Load shows the forecast adjusted for thepeffiect of the demand-side programs and is the basis for review of Dion Nrth Caroina Power expected system capacity requirements.

.4) Total Installed Capability represents the total system' capability.-

) As a :result of the turbine upgrade proect a athountytheabity Of the units iS being upgraded..

6) he ompan-y's Fim Purchases trepresent the 145 MW purchase agreement with Southeastern Power Admiistration (SERA) and the Non-Utility Gne-ratio purchase agreements for which the Compasny has contracted to purchase cacity an etrgy from these facilities.

7) Futr capacity will be -ac ir from market puxvhaes

xor, if econommical Compan1 Y

contriuoti~on.

S) The reserve margi4s presented here have been derived using a: 12.5%; reserve margin riterimn in the -sumer peaking season.

) T E

reast has been adjusted for Demand-Side Management programs and is, sh in g:h

Sectilon 2: Tabular Informallon Table 2-1: NCEMC System Projected Summer Load and Capocity (MWI 2,04 2If05 2006 to?

200 210 010 2000 tell fool 20I4 t.moswww 2.623 2.665 2.142 2.794 2XV; 2.090 f.9S 3.079 Io.0 961 3.2.2

~)m~

06U~one423 233 23 2

233 23

-2" 232 23 3

233 400

.4 2009 6511" 6M0 67Z

,732 2196

.0 6209 CbdI

fSEaiw, 24 634 624 624 674 634 624 634 614 624 624 thxt1lt to taI to Is 1ft le l

le of IFPA A*VVR To n?

rt it7 TY Ty Ty 7

PPutk 2fl5 20 m"

705 205 20S 205 t

a 0

0 lc son pwoctl 6s75 rso 750 ttOo Ir7 e7e 870 6e rtro "G

S4S SCI kW eG Rh 250 20 25I 2"

250 250 250 7s0 "a0 a

a A6P1ftB otn0Retef Ise te 105 0

IsO ne 150 ISo 150 050 0

0 Po"wPPA 720 ISO ISO ISO 05e 150 150 150 I50 460 t50 SCt UO Peio 100 to0 6

a 0

0 0

o 0

a o

S rzAhio t00.

tOO a

0 0

0 e e

0 0

o Oo Akl s0o 0

0 0

0 a

0 0

a a

P.CPA." Rogoe 60 0

0 0

0 66 0

0a IPV P002SUPomwid a

t e10 0

0 a

0-0 0

TOMi PdWS1 Wt Wpoe Aeft PMW 2.65 2.332 1.65t 1.612 t0ro7

.70 2 1 r702 0.49, 1.97?

I.01 o72 teWbple00y ;Sclsleotb.wdnOeat enwto' 634 506 sit 5gi 906 454 454 332 332 212 225 14,Anogon kw po" ueipbe 11t (UV" 2.404 2.45?

2.S56 2.65t 2jt 27 2.920 2.020 2.tt37 I.rT 2.446 2.223 f

rea.NWj0 O

0 0

e50 no 250 f65 900 Rewsue CsacsPMW)'

or 6

525 026 146 536 041 029 040 I26 ETM IGWh_

040-51r02 II 4 11t784 S

t020 5

li2 t 2i 14 1000 t02 90 12a5 O TotWl Demand Is NCEMCs Participating Member coinddenl peatk (NCEMC CP) measured el genertion.

2 Demand Side Management Includes customer owned generation. 1l0erupilble load and residential toad managemnnt as reported by NCEMC's Participaling Member cooperatives, mostly In PEC supply area.

'Chlawba Nudear Staion ownership capacity reltects both Participaltg and independent Members, as the ownership Is by NCEMC.

NcEMcasstimes altlcpactypurchases wil be 100Y. firmwith reservespravided bythe supplsngentiy. Plrther. Purchased Rescurces are forPafldpating and Independenl Members.

5SEPA Allocatiorns are for Paul;iting Members The CPML Peakkig Resource eonlrad epiresIn 2004; NCEMC has an option to exlend the purchase to 2005.

7Undeslgnated Resources will be adjusted to Include reserves ti the future for Ihose resowces that are rot firm.

6 All purchases Included reserves. Fulture purchasers WI Include reserves or NCt-MC WM acquire them Independently.

FEnergy values are measured at generation for Partidpallng Members, 8 m rnI

-L K Fin tZ

Setlin :-Z.

Tabulakr $nrorifa.t.

Tabl* 2-2: NCEMC System ProjecLYWinier LOad Sntt C6apta*%j tMW ZC=wt t

LS.-

2.73 2421 2.V(3W "49.3 291MI

=2.6) 2".3 Z

1 33 2?

50, 2A' 2a 2.40312 C*odt lhwi::lt.

b.

h614

.41 a

74 Of4 A4 Qn4 Au 4

324 67 34P Dlb 6

612

.67 672 312 312 67 672 Toli b

l 642 642

.42 312t 3,614 1

4

.614-1.14i 3.614 1634 14 CE*20 5

230 230 a,0 0

° AISOt4elu 1*

t 1S 1t0 33 i$30 0

4*"

I"0 11(3 0

vI.1WA,"oI.eA 6

20 3

1<

13 3J 1W0 10 J0:

10 136 302 0PoI (rdo:egd-o sft4Ptll43 5

33 Sig 0 ri 0

6PEC 600

~

b l

R U

4 o

(3 6

o 0

o 6

r~$Pu^dsps eff t

t

• 16 26 2,1 1.7

,1 1.70-1.73*

.70 it6 1,67 1.041 thilCEe3E30rsrt.f~~4mbfiw

~

6)

'624 313:

333 516 5II.

434 43 i6i1 232:

2 34"wurm~~7e**wstf4 2t45 46 2,41 2.3 t27 2.766 2".63 2.16

.7

2.

2490vi tktdeoAl6nu6I**(

33 0

00 e

3 0

0 0

-o 200 230 623F 60~ ~

~

=kM W

flsitC~ncltvIUwl 167 i

132 60$

4i 41 404 (315 sO6 5,18 612i

3

'Total Demand :i3 NCECPareiiftln MOMi90 en eall T4GE

• ~ measured al gene0..

2 Detrm4Side anlagofnt In fides:cusLonttoWted gneraot, IblenftPbJO bed and resWdenfit bade n Lg enaC lp NCEMs-P3iptng Membrcoop ves. nmdsily in PEC. Sup*-.m&

f Coirba t~berSlaorh t

aIlisbttug 6nd(nilependent Memberb, Ae tshiplsbtCEC.

4 NCEMC assumes all capacity pac as b 100%

wth pr d bi pytiesu.

rthter.

Psithoied aeorces r.Pa ipman d ldedndetI e

rs SEPA Afamihet ate Ibr Pav11cdpatng Members

• 'thCPAL Peakditg Resource conrtad explres In 204. fiCEft hasan option rextend the puthose to i0os.

'Undestloated Resoutieswin be-adijusted lo hricude res It or

.1036 14resoires th*t 4e not firm.

A pu7 me liluded reetvs Ft tut7 i

r e

i N

vaequire het kIdep ndeAl"ly tEnegy vatues are measured generton for idpalng0 nibe*

tot t

r ye b"ginn Jns.

North Carolina Electric IOU Service Area Map

- A)xe

=,~H'f 3

DOE/EIA-0628(2000)

Renewable Energy 2000:

Issues and Trends February 2001 Energy Information Administration Office of Coal, Nuclear, Electric and Alternate Fuels U.S. Department of Energy Washington, DC 20585 This report is available on the Web at:

http ://www.eia.doe.gov/cneaf/solar.renewables/rea~issues/rea_issues~-sum.htmL.

This report was prepared by the Energy Information Administration, the independent statistical and analytical agency within the U.S. Department of Energy. The information contained herein should be attributed to the Energy Information Administration and should not be construed as advocating or reflecting any policy of the Department of Energy or any other organization.

(xCDC A-2 O 0!

Electricity Demand and Supply Continued Growth in Electricity Use Is Expected in All Sectors Early Capacity Additions Use Natural Gas, Coal Plants Are Added Later Figure 66. Annual electricity sales by sector, 1970-2025 (billion kilowatthours) 2,500 -

I Priecipns Figure 67. Electricity generation capacity additions by fuel type, including combined heat and power, 2004-2025 (gigawatts) 120-Auk vet I

. v>s>e Vito 2,000 -

1,500 -

CobmmercWl

• Residential 80 -

Coal KRerewa

• Industriad 40 -

I-Is. I1 II IiI 0

Mu NX*

l 0

I 1970 1980 1990 2003 2015 2025 2004-2006-2011-2016-2021-2005 2010 2015 2020

, 2025 Total electricity sales are projected to increase at an average annual rate of 1.9 percent in the AE02005 reference case, from 3,481 billion kilowatthours in 2003 to 5,220 billion kilowatthours in 2025 (Figure 66). From 2003 to 2025, annual growth in electricity sales is projected to average 1.6 percent in the resi-dential sector, 2.5 percent in the commercial sector, and 1.3 percent in the industrial sector.

The average size of homes is projected to be larger in 2025 than in 2003 in terms of both square footage and ceiling height, with corresponding increases in elec-tricity use for heating, cooling, and lighting. In addi-tion, expected population shifts to warmer climates increase the amount of electricity used for air condi-tioning, although the projected increases are miti-gated in part by the implementation of a more stringent efficiency standard for air conditioners and heat pumps in 2006.

Projected efficiency gains for electric equipment in the commercial sector are offset by the continuing penetration of new telecommunications technologies and medical imaging equipment, increased use of office equipment, and more rapid additions of floorspace.

Although electricity use is projected to increase with the growth of industrial output, increases in electric-ity sales to the industrial sector are expected to be off-set by a 2.7-percent average annual increase in onsite generation.

With growing electricity demand and the retirement of 43 gigawatts of inefficient, older generating capac-ity, 281 gigawatts of new capacity (including end-use combined heat and power) will be needed by 2025.

Most retirements are expected to be older oil-and natural-gas-fired steam capacity, along with smaller amounts of older oil-and natural-gas-fired combus-tion turbines and coal-fired capacity, which are not competitive with newer natural gas combustion tur-bine or combined-cycle capacity.

More than 60 percent of new capacity additions are projected to be natural-gas-fired combined-cycle, combustion turbine, or distributed generation tech-nologies (Figure 67). More than 80 percent of the capacity additions will be needed after 2010, when the current excess of generation capacity has been reduced. As natural gas prices rise later in the fore-cast, new coal-fired capacity is projected to become increasingly competitive, accounting for nearly one-third of the capacity expansion expected in the refer-ence case. Most of the new coal capacity is expected to use advanced pulverized coal technology and to begin operation after 2015. About 16 gigawatts of capacity using advanced clean coal technology, with higher capital costs but relatively low fuel costs, is also expected to be added.

About 5 percent of the projected capacity expansion consists of renewable generating units. Another 7 gigawatts of distributed generation, mostly gas-fired microturbines, is also expected to be added by 2025.

Oil-fired steam plants with higher fuel costs and lower efficiencies are expected to be used only for new industrial combined heat and power capacity.

Energy Information Administration / Annual Energy Outlook 2005 87

'I.

Electricity Supply Capacity Additions Are Expected To Be Required in All Regions Figure 68. Electricity generation capacity additions, including combined heat and power, by region and fuel, 2004-2025 (gigawatts)

ECAR ERCOT MAAC MAIN MAPP NY Natural gas NE Coal V

FL

_Renewablel

-SERC other SPP NWP RA CA 0

10 20 30 40 50 60 Most areas of the United States currently have excess generation capacity, but all the electricity demand regions (see Appendix G for definitions) are expected to need additional, currently unplanned, capacity by 2025 (Figure 68). Some new plants already are under construction, nearly all of which are expected to be completed by 2010.

The need for new capacity is expected to be greatest in the Southeast and the West. Although comparatively small geographically, the Southeast accounts for about 30 percent of projected total demand in 2025 and a comparable share of expected capacity addi-tions. The size of the region's electricity market is the principal reason for the amount of new capacity required, and the projected growth in its demand for electricity growth is also slightly higher than the national average. The West, which geographically is the largest electricity demand region, currently rep-resents less than 20 percent of the Nation's total electricity demand, but it accounts for 25 percent of projected capacity additions. Relatively strong growth in demand is projected for the West.

Capacity additions in the Southeast and the West are expected to be considerably more diverse than in the other areas of the country, where most additions are projected to be natural-gas-fired capacity. Almost all additions of coal-fired and renewable capacity are expected to be in these two areas. Of the 87 gigawatts of new coal-fired capacity, the Southeast and West account for 36 percent and 40 percent, respectively.

Nationally, new renewable generating capacity is expected to total 15 gigawatts, with 28 percent and 34 percent located in the Southeast and West.

Natural Gas and Coal Meet Most Needs for New Electricity Supply Figure 69. Electricity generation by fuel, 2003 and 2025 (billion kilowatthours) 3,000 -

2,500 -

2,000 -

-2003

-2025 1,500 -

1 1,000 -

500 -

Coal Nuclear Natural gas Renewables Oil Coal-fired power plants are expected to continue sup-plying most of the Nation's electricity through 2025 (Figure 69). In 2003, coal-fired plants (including utili-ties, independent power producers, and end-use combined heat and power) accounted for 51 percent (1,970 billion kilowatthours) of all electricity genera-tion. Their output is projected to increase to 2,890 bil-lion kilowatthours in 2025, while their share of total generation declines to 50 percent as a result of a rapid increase in natural-gas-fired generation.

In compliance with environmental regulations, about one-third of existing coal-fired capacity has been fit-ted with scrubbers to reduce sulfur dioxide emissions, and another 27 gigawatts of currently existing capac-ity is expected to have scrubbers in 2025. A total of87 gigawatts of new coal-fired capacity is projected to be added in the reference case, mostly after 2010, as nat-ural gas prices continue to rise. Nuclear generation, currently the second-largest source of electricity, is expected to increase modestly, as a result of addi-tional improvements in plant performance and expansions of existing capacity, before leveling off after 2017.

Natural gas is expected to have the largest increase in its share of total electricity generation, from 17 per-cent in 2003 to 20 percent in 2010 and 24 percent in 2025, and by 2010 it is expected to overtake nuclear power as the second-largest source of electricity pro-duction. Generation from renewable sources, includ-ing hydropower, is projected to increase by 36 percent from 2003 to 2025, but its share of total electricity supply is projected to decline from 9 percent in 2003 to 8 percent in 2025.

88 8Energy Information Administration / Annual Energy Outlook 2005

Electricity Supply Nuclear Power Plant Capacity Factors Are Expected To Increase Modestly Figure 70. Electricity generation from nuclear power, 1973-2025 (billion kilowatthours) 1,000 -

800-600 -

400 -

200 -

Least Expensive Technology Options Are Likely Choices for New Capacity Figure 71. Levelized electricity costs for new plants, 2015 and 2025 (2003 mills per kilowatthour) 75 -

Incremental transmission costs Variable costs, including fuel E

-PhFied costs Capital costs:

51 l 0 -000f I

I Fixd csts i:

O _

_ill 2015 Coal Gas, Wind Nuclear combined cycle I

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History 1970 1980 1990 2003 2015 2025 The United States currently has 104 commercial nuclear reactors licensed to operate, providing about 20 percent of the total 3,690 billion kilowatthours of electricity generated in 2003 (Figure 70). The perfor-mance of U.S. nuclear units has improved recently; the national average capacity factor rose to 90 percent in 2002 before dropping slightly to 88 percent in 2003.

It is assumed that performance improvements will continue even as the plants age, leading to a weighted average capacity factor of 92 percent after 2010.

In the reference case, no nuclear units are projected to be retired from 2003 to 2025. Nuclear capacity grows slightly, due to assumed increases at existing units. The U.S. Nuclear Regulatory Commission (NRC) approved 8 applications for power uprates in 2003, and another 12 were approved or pending in 2004. The reference case assumes that all the uprates will be carried out, as well as others expected by the NRC over the next 15 years, leading to an increase of 3.5 gigawatts in total nuclear capacity by 2025. No new nuclear units are expected to become operable between 2003 and 2025.

Nuclear units would be retired if their operation were no longer economical relative to the cost of building replacement capacity. By 2025, the majority of nuclear units will be beyond their original license expiration dates. As of December 2004, license renew-als for 30 nuclear units had been approved by the NRC, and 16 other applications were being reviewed.

As many as 28 additional applicants have announced intentions to pursue license renewals over the next 3 years, indicating a strong interest in maintaining the existing stock of nuclear plants.

Technology choices for new generating capacity are made to minimize cost while meeting local and Federal emissions constraints. The choice of technol-ogy for capacity additions is based on the least expen-sive option available (Figure 71) [1361. The reference case assumes a capital recovery period of 20 years. In addition, the cost of capital is based on competitive market rates, to account for the risks of siting new units.

Capital costs are expected to be reduced over time (Table 27), at rates that depend on the current stage of development for each technology. For the newest technologies, capital costs are initially adjusted upward to reflect the optimism inherent in early esti-mates of project costs. As project developers gain experience, the costs are assumed to decline. The decline continues at a progressively slower rate as more units are built. The performance (efficiency) of new plants is also assumed to improve, with heat rates for advanced combined cycle and coal gasifica-tion units declining to 6,333 and 7,200 Btu per kilo-watthour, respectively, by 2010.

Table 27. Costs of producing electricity from new plants, 2015 and 2025 Costs 2015 Advanced Advanced combined coal cycle 2003 mills per 31.68

'11.63 4.59 1.36 12.28 34.88 2025 Advanced Advanced combined coal cycle kilowatthour 28.87 11.08 4.59 1.36 13.98 39.06 Capital Fixed Variable Incremental transmission Total 3.24 2.80 3.41 2.86 51.79 50.67 50.85 54.36 Energy Information Administration / Annual Energy Outlook 2005 89

Electricity Fuel Costs and Prices Coal and Nuclear Fuel Costs Are Expected To Be Stable Average Electricity Prices Decline From 2001 Highs, Then Gradually Rise Figure 72. Fuel prices to electricity generators, 1990-2025 (2008 dollars per million Btu) 6-History L

Prjections Amazon Figure 73. Average U.S. retail electricity prices, 1970-2025 (2003 cents per kilowatthour) 12-History Projections 10-I gas 5-8-

4.

3 2-6-

4-2 -

1 -

0 0

1970 1980 1990 X

At 2003 2015 1990 1995 -

2003 2010 2015 2020 :2025 2025 Electricity production costs are a function of the costs for fuel, operations and maintenance, and capital.

Fuel costs make up most of the operating costs for fos-sil-fired units. For a new coal-fired plant built today, fuel costs would represent about one-half of total operating costs, whereas the share for a new natu-ral-gas-fired plant would be almost 90 percent. For nuclear units, fuel costs typically are a much smaller portion of total production costs, and nonfuel opera-tions and maintenance costs make up a much larger share.

The impact of higher natural gas prices in the projec-tions is offset by increased generation from coal-fired and nuclear power plants and by higher generation efficiencies as new capacity is installed. Although natural gas prices have been volatile in recent years, delivered prices to electricity generators are projected to peak at $6 per million Btu in 2004, then drop by almost 30 percent by 2010 before climbing steadily to almost $5.50 per million Btu in 2025 (Figure 72).

Nuclear fuel costs, currently around $0.40 per million Btu (roughly 4 mills per kilowatthour), are projected to rise to about $0.60 per million Btu in 2025.

Delivered petroleum prices to electricity generators follow a price path similar to that for natural gas prices, with a sharp drop through 2010 followed by a steady rise through 2025. Despite increasing fuel costs, the natural gas share of total generation is projected to increase from 16 percent in 2003 to 24 percent in 2025 because of the higher efficiency of gas-fired capacity.

Average U.S. electricity prices, in real 2003 dollars, are expected to decline by 11 percent, from 7.4 cents per kilowatthour in 2003 to 6.6 cents in 2011 (Figure 73), then rise to 7.3 cents per kilowatthour in 2025.

Prices follow the trend of the generation cost compo-nent of price, which makes up 65 percent of the total price of electricity and changes mainly in response to changes in natural gas prices. The distribution com-ponent, 28 percent of the total electricity price, is expected to decline from 2003 to 2025 at an average annual rate of 0.7 percent, as the cost of distribution infrastructure is spread over a growing amount of total electricity trade. Transmission prices are expected to increase at an average annual rate of 1.0 percent because of the additional investment needed to meet projected growth in electricity demand. Elec-tricity prices for individual customer classes are pro-jected to follow the average price trend, declining through 2011 and then increasing for the remainder of the forecast. Residential and commercial prices in 2025 are projected to be slightly lower than 2003 prices, and industrial prices are expected to be slightly higher than in 2003.

Competition in retail and wholesale generation mar-kets can strongly influence electricity prices. In 2004, 17 States and the.District of Columbia had competi-tive retail electricity markets in operation. Montana, Nevada, New Mexico, and Oklahoma have delayed opening competitive retail markets; Arkansas has repealed its restructuring legislation; and Califor-nia's competitive retail market is suspended. Many States have cited a lack of operational wholesale mar-kets and inadequate generation and transmission capacity as reasons for delaying retail competition.

90 Energy Information Administration / Annual Energy Outlook 2005

Electricity From Renewable Sources Increases in Nonhydropower Renewable Generation Are Expected Figure 74. Grid-connected electricity generation from renewable energy sources, 1970-2025 (billion kilowatthours) 400 -

History l

Pojections Biomass, Wind, and Geothermal Lead Growth in Renewables Figure 75. Nonhydroelectric renewable electricity generation by energy source, 2003-2025 (billion kilowatthours) 200-150 -

100 -

50 -

0 -

8 9

0 1

1970 1980 1990 2008 2015 2025 0

2008 2010 2020 2025 Despite strong growth in renewable electricity gener-ation as a result of technology improvements and expected higher fossil fuel costs, grid-connected gen-erators using renewable fuels (including combined heat and power and other end-use generators) are projected to remain minor contributors to U.S. elec-tricity supply. From 359 billion kilowatthours in 2003 (9.3 percent of total generation) renewable genera-tion increases to only 489 billion kilowatthours (8.5 percent) in 2025 (Figure 74).

Conventional hydropower remains the major source of renewable generation in the AE02005 reference case. After 4 years of below-normal precipitation, hydroelectric generation is expected to recover in 2005; however, with little new capacity expected, con-ventional hydropower generation is projected to increase from 275 billion kilowatthours in 2003 (7.1 percent of total generation) to just 307 billion kilowatthours (5.3 percent of the total) in 2025. Other renewables account for 5.3 percent of projected addi-tions to capacity from 2003 to 2025 and 6.4 percent of the projected increase in generation. Generation from nonhydropower renewables increases from 84 billion kilowatthours in 2003 (2.2 percent of generation) to 182 billion kilowatthours in 2025 (3.2 percent). Bio-mass, including combined heat and power systems and biomass co-firing in coal-fired plants, is the larg-est source of other renewable generation in the fore-cast. Electricity from biomass combustion increases from 37 billion kilowatthours in 2003 (1.0 percent) to 81 billion kilowatthours in 2025 (1.4 percent), with 49 percent of the increase coming from dedicated power plants and the rest primarily from combined heat and power.

AE02005 projects significant increases in electricity generation from both geothermal and wind power (Figure 75). In the West, geothermal output increases from 13 billion kilowatthours in 2003 to 33 billion kilowatthours in 2025. Wind-powered generating capacity increases from 6.6 gigawatts in 2003 to 11.3 gigawatts in 2025, and generation from wind capacity increases from less than 11 billion kilowatthours in 2003 to 35 billion in 2025. The mid-term prospects for wind power are uncertain, depending on response to the recent extension of the Federal production tax credit through 2005 and the likelihood of further extensions, as well as responses to State programs, technology improvements, transmission availability, and public interest.

Generation from municipal solid waste and landfill gas (MSW/LFG) is projected to increase by 7 billion kilowatthours, to 29 billion kilowatthours in 2025, but little new municipal solid waste capacity is expected. Solar technologies generally are projected to remain too costly to be competitive in supplying power to the grid. Central-station photovoltaic capac-iity increases in the forecast from about 40 megawatts in 2003 to 400 megawatts in 2025, and solar thermal capacity increases from about 400 megawatts to more than 500 megawatts. In contrast, individual grid-con-nected photovoltaic installations grow rapidly, from Rout 60 megawatts in 2003 to nearly 1,800 mega-watts in 2025. Grid-connected photovoltaics and solar thermal, which together provided about 0.7 billion kilowatthours of electricity in 2003, are projected to supply nearly 6 billion kilowatthours in 2025 [137].

Energy Information Administration / Annual Energy Outlook 2005 91

Electricity From Renewable Sources State Programs Will Continue To Support Renewable Energy Use Figure 76. Additions of renewable generating capacity, 2003-2025 (gigawatts) 6-Renewables Are Expected To Become More Competitive Over Time Figure 77. Levelized and avoided costs for new renewable plants in the Northwest, 2010 and 2025 (2003 mills per kilowatthour) 5-4-

3-2-

I -

0-Geothermal Solar thermal Biomass Wind Geothermal Solar thermal Biomass

%;: l: Wind 2010 Levelized cost Avoided cost 2025 I

I 25 50 Biomass Geo-Landfill Solar : Wind thermal gas 0

i I

I I

I 75 100.

125 150 In the AE02005 reference case, 14.9 gigawatts of new nonhydroelectric renewable energy capacity is pro-jected to enter service from 2003 through 2025, including 10.6 gigawatts in the electric power sector, 2.6 gigawatts of combined heat and power, and 1.7 gigawatts of end-use applications. In the electric power sector, 1.6 gigawatts is projected as a result of State requirements and goals (wind 1.3 gigawatts, geothermal and landfill gas each 0.1 gigawatt, plus smaller amounts of biomass, waste, and solar capac-ity) and the rest from commercial projects (Figure 76).

I Most new renewables capacity projected in the near term results from specific projects and State pro-grams. After 2010, the projected growth in renewable energy capacity is based on its ability to become com-petitive in electricity markets. The Federal produc-tion tax credit for wind plants was not extended until late in 2004, and so only 213 megawatts of new wind capacity is expected to be completed in 2004. In 2005,l however, more than 1 gigawatt of new capacity is expected to enter service before the credit expires on December 31.

Because States with renewable energy requirements have not added capacity as rapidly as projected in earlier forecasts, projections for new capacity resulting from State renewable portfolio standards, mandates, and nonmandatory goals are reduced in AE02005, but they are still significant, including 903 megawatts expected in Texas, 146 megawatts each in California and Minnesota, 141 megawatts in Nevada, 80 megawatts in New Mexico, and 65 mega-watts in Pennsylvania.

The competitiveness of both conventional and renew-able generation resources is based on the most cost-effective mix of capacity that satisfies the demand for electricity across all hours and seasons. Baseload technologies tend to have low operating costs and set the marginal cost of power only during the hours of least demand. Dispatchable geothermal and biomass resources compete directly with new coal and nuclear plants, which to a large extent determine the avoided cost -[138] for baseload energy (Figure 77). In some regions and years, new geothermal or biomass plants may be competitive with new coal-fired plants, but their development is limited by the availability of geo-thermal resources or competitive biomass fuels.

Intermittent technologies-specifically, wind and solar-can be used only when resources are available.

Because of their relatively low operating costs and limited resource availability, the avoided costs of these technologies are determined largely by the operating costs of the most expensive units operating when their resources are available. Solar generators tend to operate during peak load periods, when gas-fired combustion turbines and combined-cycle units with higher fuel costs tend to determine avoided cost. The levelized cost of solar thermal generation is projected to be significantly higher than its avoided cost through 2025. The availability of wind resources varies among regions, but wind plants generally tend to displace intermediate load generation. Thus, the avoided costs of wind power will be determined largely by the low-to-modest operating costs of com-bined-cycle and coal-fired plants. In some regions and years, the levelized costs for wind power are projected to be below its avoided costs.

92 Energy Information Administration / Annual Energy Outlook 2005

Electricity Alternative Cases Gas-Fired Technologies Lead New Additions of Generating Capacity Figure 78. Cumulative new generating capacity by technology type in three fossil fuel technology cases, 2003-2025 (gigawatts) 250-Coal 200 -

150 -

Advanced coal Natural gas

-Advanced gas Ff, -

Renewables Sensitivity Cases Look at Possible Reductions in Nuclear Power Costs Figure 79. Levelized electricity costs for new plants by fuel type in two nuclear cost cases, 2015 and 2025 (2003 cents per kilowatthour) 10 -

-Incremental transmission costs 2025 Variable costs, including fuel 8

2015 Fixed costs Capital costs 6 5I ii 24-Ii 100 -

SO -

1.1i-Ii I

Coal Natural gas combined cyce Nuclear:

Nuclear:

Nuclear:

reference advanced vendor case cost case estimate case

• EU

_I _ _

Low fossil Reference High fossil The AE02005 reference case uses the cost and perfor-mance characteristics of generating technologies to select the mix and amounts of new generating capac-ity for each year in the forecast. Values for technology characteristics are determined in consultation with industry and government specialists, but uncertainty surrounds the assumptions for new technologies. In the high fossil fuel case, capital costs, heat rates, and operating costs for advanced fossil-fired generating technologies (integrated coal gasification combined cycle, advanced combined cycle, and advanced com-bustion turbine) reflect a 10-percent reduction from reference case levels in 2025. The low fossil fuel case assumes no change in capital costs and heat rates for advanced technologies from their 2005 levels.

Natural gas technologies make up the largest share of new capacity additions in all cases, but the mix of cur-rent and advanced technologies varies (Figure 78). In the high fossil fuel case, advanced technologies are used for 84 percent (173 gigawatts) of projected gas-fired capacity additions, compared with 69 per-cent (110 gigawatts) in the low fossil fuel case. The coal share of total capacity additions varies from 22 percent to 33 percent in the cases. In the low fossil fuel case, only a negligible amount of advanced coal-fired generating capacity is added. In the high fossil fuel case, advanced coal technologies are more competitive, making up 65 percent of all coal-fired capacity additions. The projections for average fossil fuel efficiency in the electric power sector in 2025 are 37 percent in the reference case, 38 percent in the high fossil fuel case, and 36 percent in the low fossil fuel case, based on different assumptions about the penetration of advanced technologies in the cases.

The AE02005 reference case assumptions for the cost and performance characteristics of new technologies are based on cost estimates by government and indus-try analysts, allowing for uncertainties about new, unproven designs. Two alternative nuclear cost cases analyze the sensitivity of the projections to lower costs for new nuclear power plants. The advanced nuclear cost case assumes capital and operating costs 20 percent below the reference case in 2025, reflect-ing a 28-percent reduction in overnight capital costs from 2005 to 2025. (Earlier analysis showed that a 10-percent reduction in capital and operating costs would be insufficient to stimulate new nuclear con-struction.) The vendor estimate case assumes reduc-tions relative to the reference case of 18 percent initially and 38 percent in 2025. These costs are con-sistent with estimates from British Nuclear Fuels Limited for the manufacture of its advanced pressur-ized-water reactor (AP1000). Cost and performance characteristics for all other technologies are assumed to be the same as those in the reference case.

Projected nuclear generating costs in the two alterna-tive nuclear cost cases are competitive with the generating costs projected for new coal-and natural-gas-fired units toward the end of the projection period (Figure 79). In the advanced nuclear case 7 gigawatts of new nuclear capacity is added by 2025, and in the vendor estimate case 25 gigawatts is added by 2025.

The additional nuclear capacity displaces primarily projected new coal-fired capacity. The projections in Figure 79 are average generating costs, assuming generation at the maximum capacity factor for each technology; the costs and relative competitiveness of the technologies could vary across regions.

Energy Information Administration / Annual Energy Outlook 2005 93

Electricity Alternative Cases Rapid Economic Growth Would Boost New Coal and Renewable Capacity Figure 80. Cumulative new generating capacity by technology type in three economic growth cases, 2003-2025 (gigawatts) 200 -,

Nnfural,

Lower Cost Assumptions Increase Biomnass and Geothermal Capacity Figure 81. Nonhydroelectric renewable electricity generation by energy source in three cases, 2010 and 2025 (billion kilowatthours) 250-High renewables Low renewables 200-Reference l

l IXGeathern 150 -

100 -

Low growth Reference High growth The projected annual average growth rate for GDP from 2003 to 2025 ranges from 3.6 percent in the high economic growth case to 2.5 percent in the low economic growth case. The difference leads to a 4-percent change in projected electricity demand in 2010 and a 12-percent change in 2025, with a corre-sponding difference of 105 gigawatts in the amount of new capacity projected to be built from 2003 to 2025 in the high and low economic growth cases, including combined heat and power in the end-use sectors.

Most (74 percent) of the new capacity projected to be needed in the high economic growth case beyond that added in the reference case is expected to consist of new coal-fired plants. The stronger demand growth assumed in the high growth case is also projected to stimulate additions of renewable plants and new natural-gas-fired capacity (Figure 80). In the low eco-nomic growth case, total capacity additions are reduced by 53 gigawatts, and 70 percent of that pro-jected reduction is in coal-fired capacity additions.

Average electricity prices in 2025 are 5 percent higher in the high economic growth case than in the refer-ence case, due to higher natural gas prices and the costs of building additional generating capacity.

Electricity prices in 2025 in the low economic growth case are projected to be 4 percent lower than in the reference case. In the high economic growth case, a 5-percent increase in consumption of fossil fuels results in a 6-percent increase in carbon dioxide emissions from electricity generators in 2025.

The impacts of key assumptions about the availability and cost of nonhydroelectric renewable energy resources for electricity generation are shown in two alternative technology cases. In the low renewables case, the cost and performance of generators using renewable resources are assumed to remain unchanged throughout the forecast. The high renew-ables case assumes cost reductions of 10 percent in 2025 on a site-specific basis for hydroelectric, geo-thermal, biomass, wind, and solar generating capacity (however, no new additions of conventional hydropower are projected in any of the cases, given the lack of suitable new sites for.development).

In the low renewables case, construction of new renewable capacity is less than projected in the refer-ence case (Figure 81). In the high renewables case, more additions of biomass, geothermal, and wind capacity are projected through 2025 than in the refer-ence case, with most of the incremental capacity added between 2010 and 2025. In 2025, projected total electricity generation from nonhydropower renewables is 52 billion kilowatthours higher in the high renewables case than in the reference case, with most of the increment coming from geothermal (22.8 billion kilowatthours), biomass (18.0 billion kilowatt-hours), and wind energy (10.1 billion kilowatthours).

Still, nonhydropower renewables are projected to remain relatively small contributors to total genera-tion in the high renewables case, accounting for 134 billion kilowatthours (2.9 percent of the total) in 2010 and 235 billion kilowatthours (4.1 percent) in 2025.

94 Energy Information Administration I Annual Energy Outlook 2005

(NOEuca Pn BranPo e< t-z-Nuclear Plants - Brunswick Page I of 2

-D eiai ArMTErras Home > Nuclear > U.S. Nuclear Reactors > Brunswick U.S. Nuclear Plants Brunswick North Carolina Unit I Nuclear system supplied by General Electric Company (U.S.)

Capacity Generation Capity Type On-line License Net MW(e) in 2003 Factor Date Expiration Date Megawatthours 847 7,701,828 103.5 %

BWR Nov. 12, 1976 Sept. 8, 2016 Unit 2 Nuclear system supplied by General Electric Company (U.S.)

Capacity Net MW(e)

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811 BWR=Boiling Water Reactor

==

Description:==

The Brunswick power plant, named for the county in which it is located, covers 1,200 acres. The site is adjacent to an agricultural area and to wetlands and woodlands.

Ownership: The majority owner (81.7 percent) of the Brunswick nuclear plant is the Progress Energy Corporation. The North Carolina Eastern Municipal Power Agency operators the plant and owns the remaining 18.3 percent.

The Impact of the Nuclear Industry on North Carolina:

0 0

0 a

0 News item: State Energy Plan: June 2003 Highlights Nuclear-provided Electricity Generation Competition in the State Electricity Market Environmental Trends: Emissions levels Various Links to related sites.

Sources: Capacity, for purposes of this report, is the net summer capability as reported in Energy Information Administration (EIA) survey form 860, "Annual Electric Generator Report." Capacity Factor is a calculation in which the maximum possible generation (based on net summer capability) is divided into the actual generation than multiplied by 100 to get a percentage. Generation is the electricity output reported by plant owners on EIA survey I.

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I j-VAS Nuclear Plants - Brunswick Page 2 of 2 form 906. Type of Unit: All U.S. commercial reactors currently, in operation are one of two types: BWR (boiling water reactor) or PWR (pressurized light water reactor). The type is identified in EIA's Nuclear Power Generation and Fuel Cycle Report. Both the On-line Date and the License Expiration Date are reported annually in Information Digest by the U.S.

Nuclear Regulatory Commission.

Contact:

John Moens Email: John.Moens(eia.doe.gov Phone: (202) 287-1976 EIA Home Contact Us Page last modified on Fri Mar 18 07:14:46 PST 2005.

URL: http://www.eia.doe.gov/cneaf/nuclear/page/at_a_glance/reactors/brunswlck.html I

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I HLE - Fossil Energy: DOE's Fuel Cell R&D Program 0a, (DOE 2co4)

Page 1 of3 SEARCH

> Coal & Natural Gas Home > Coal & Natural Gas Power Systems > Fuel Cell R&D PowerSystems Future Fuel Cells R&D

> Carbon Sequestration

> Hydrogen & Other Clean Fuels

> Oil & Gas Supply &

Delivery

> Natural Gas Regulation

> Electricity Regulation

> Petroleum Reserves "So we're creating the National Climate Change Technology Initiative...to fund demonstration projects for cutting-edge technologies, such as fuel cells."

President George W. Bush June 11, 2001 Fuel cells are an energy users dream: an efficient, combustion-less, virtually pollution-free power source, capable of being sited in downtown urban areas or in remote regions, that runs almost silently, and has few moving parts.

'I Advanced Searc E New Electr Technolog' Fuel-Cell C More Rele PI Database (

R&D Proje, ES National Et Technolog' Web Site MORE INFO X Phosphoric Acid Fuel Cells W Molten Carbonate Fuel Cells V Solid Oxide Fuel Cells Solid State Energy Using an electrochemical process discovered more than Conversion Alliance 150 years ago, fuel cells began supplying electric power for spacecraft in the 1960s. Today they are being used in more down-to-earth distributed generation applications: to provide on-site power (and waste heat in some cases) for military bases, banks, police stations, and office buildings from natural gas. In their most successful commercial applications, fuel cells convert the energy in waste gases from water treatment plants to electricity.

In the near future, fuel cells could be propelling automobiles and allowing homeowners to generate electricity-in their basements or backyards.

Go to DOE Home Page Fuel cells operate much like a battery, using electrodes in an electrolyte to generate electricity. Unlike a battery, however, fuel cells never lose their charge. As long as there is a constant source of fuel - usually hydrogen produced from natural gas, and air as the source for oxygen - fuel cells will generate electricity.

DOE's Stationary Power Fuel Cell Program FY 2004 An

[17MB PDF 9J Distributed' Brochure [1 E SECA Broci

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[401kB PDF Program CC 21 Mark Willia National Ei Technolog PO Box 88 U.S. Dept.

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' 4W The U.S. Department of Energy's Office of Fossil Energy is partnering with several fuel Water Hat cell developers to develop the technology for C02 the stationary power generation sector

• that is, for power units that can be connected into the electricity grid primarily as distributed generation units. Industry participation is extensive, with more than 40 percent of the program funded by the private sector. If the joint government-industry fuel cell program is successful, the world's power industry will have a revolutionary new option for generating electricity with efficiencies, reliabilities, and environmental performance unmatched by conventional electricity generating approaches.

For most of the 1970s and early 1980s,the Federal program induded development of the phosphoric acid fuel cell system, considered the "first generation" of modem-day fuel cell technologies. Largely because of the R&D support provided by the Federal program, United Technologies Corporation and its subsidiaries manufactured and sold phosphoric acid fuel cells around the world.

In the late 1980s, the department shifted its emphasis to development of advanced http://www.fossil.energy.gov/programs/powersystems/fuelcells/

10/26/2005

£ ( E - Fossil Energy: DOE's Fuel Cell R&D Program Page 2 of 3 generations of higher temperature fuel cell technologies, specifically the molten carbonate and solid oxide fuel cell systems. Federal funding for these technologies have concluded. Private commercial manufacturing facilities have been built and commercial sales have been achieved.

While first generation fuel cells continue to spur interest in fuel cell technologies, the focus of the Department of Energy's Fossil Energy fuel cell program is to develop a much lower cost fuel cell. The target is $400 per kilowatt or less, which is significantly lower (by about a factor of ten) than current fuel cell products. It is expected that lower cost fuel cells will lead to widespread utilization (see below).

Fuel Cell Benefits Fuel cells are the cleanest and most efficient technologies for generating electricity from fossil fuels. Since there is no combustion, fuel cells do not produce any of the pollutants commonly emitted by boilers and furnaces. For systems designed to consume hydrogen directly, the only products are electricity, water and heat.

When a fuel cell consumes natural gas or other hydrocarbons, it produces some carbon dioxide, though much less than burned fuel. Advanced fuel cells using natural gas, for example, could potentially reduce carbon dioxide emissions by 60% compared to a conventional coal plant and by 25% compared to modem natural gas plants. Moreover, the carbon dioxide is emitted in concentrated form which makes its capture and storage, or sequestration, much easier.

Fuel cells are so dean that, in the United States, 26 states have financial incentives to support their installation. In fact, the South Coast Air Quality Management District in southern California and regulatory authorities in both Massachusetts and Connecticut have exempted fuel cells from air quality permitting requirements. Some 16 states have portfolio standards or set asides for fuel cells. Additionally, there are major fuel cell programs in New York (NYSERDA), Connecticut (Connecticut Clean Energy Fund), Ohio (Ohio Development Department), and California (California Energy Commission). Certain states have favorable policies that improve the economics of fuel cell projects. For example, 39 states and the District of Columbia have net metering, and 19 of those have net metering for fuel cells which obligates utilities to deduct any excess power produced by fuel cells from the customer's bill.

Fuel cells are also inherently flexible. Like batteries in a flashlight, the cells can be stacked to produce voltage levels that match specific power needs; from a few watts for certain appliances to multiple megawatt power stations that can light a community.

Cost - the Major Hurdle So why aren't fuel cells being Installed everywhere there is a need for more power?

The primary reason is cost. Fuel cells developed for the; space program in the 1 960s and 1970s were extremely expensive ($600,o0o/kW) and impractical for terrestrial power applications. During the past three decades, significant efforts have been made to develop more practical and affordable designs for statiohary power applications. But progress has been slow. Today, the most widely deployed fuel cells cost about $4,500 per kilowatt by contrast, a diesel generator costs $800 to $1,500 per kilowatt, and a natural gas turbine can be even less.

Recent technological advances, however, have significantly improved the economic outiook for fuel cells.

The U.S. Department of Energy has launched a major initiative - the Solid State Energy Conversion Alliance (www.seca.doe gov) - to bring about dramatic reductions in fuel cell costs. The goal is to cut costs to as iow ps $400 per kilowatt by the end of this decade, which would make fuel cells competitive for virtually every type of power application. The initiative signifies the Department's objective of developing a modular, all-solid-state fuel cell that could be mass-produced for different uses much the way electronic components are manufactured and sold today.

Advanced Fuel Cell Research http://www.fossil.energy.gov/programs/powersystems/fuelcells/

10/26/2005

>-3)

OE - Fossil Energy: DOE's Fuel Cell R&D Program Page 3 of 3 I.

The High Temperature Electrochemistry Center (HiTEC) Advanced Research Program was created in 2002 to provide crosscutting, multidisciplinary research supporting FutureGen. HiTEC is centered at Pacific Northwest National Laboratory (PNNL) with satellite centers at Montana State University and the University of Florida. Research includes the development of low-loss electrodes for reversible solid oxide fuel cells, the development of high temperature membranes for hydrogen separation; and the study of fundamental electrochemical processes at interfaces. HiTEC Is also pursuing the development of high temperature electrochemical power generation and storage technologies and advanced fuel feedstock. Financial assistance will be provided to organizations capable of performing basic, fundamental and applied research to advance scientific understanding and devise concepts that apply new scientific insights toward advancement of novel electrochemical based power generation and energy storage technologies for use at large coal power plants.

Fuel Cells for Near Zero Emissions Coal-Based Systems The SECA Program is currently focused on small, 3-10 kW scale fuel cell systems for distributed generation applications. These relatively small fuel cells can be scaled up to larger megawatt dass systems for use as power modules in coal based applications, including FutureGen. Large fuel cell systems will then be combined with other power generation modules (e.g., a gas turbine as a fuel cell-turbine hybrid), into hybrid power systems.

Beginning in FY 2005, new work will focus on building larger cells that will be combined into stacks and the stacks will be combined into fuel cell modules that can be used as building blocks for multi-megawatt class power systems. The ultimate goal of this new initiative is the development of large (> 100 MWe) fuel cell power systems that will produce affordable, efficient and environmentally-friendly electrical power at greater than fifty percent (50% HHV) overall efficiency from coal to AC power, in systems that include C02 separation for sequestration.

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http://www.fossil.energy.gov/programs/powersystems/fuelcells/

10/26/2005

Wind Powering America: North Carolina Wind Resource Map Q2XNS Zcx05,)

Page 1 of 2 U.S. Department of Energy j Energy Efficlec and Renewable Energy Search Help u More Sear(

Wind Powering America Home About Wind Powering America Program Areas State Regional Native Americans Agricultural Sector Small Wind Public Lands Public Power Economic Development Policy EERE Informatif North, Carolina Wind Resource Map' The Depa rtment of Energy's Wind Program and the National Renewable Energy Laboratory (NREL) plublished a new wind resource map for the state of North Carolina. This resource map shows wind speed estimates I

at 50 meter above the ground 7Z-;

and depicts the resource that I

a u

-E could be used for utility-scale wind development. Future plans This map of North Carolina shows are to provide wind speed the wind resource at 50 meters.

estimates at 30 meters, which are useful for identifying small Viewing Options wind turbine opportunities Larger Jpeg: Click Map d i Printable: (PED12.5MB)

[

Download Adobe Reader As a renewable resource, wind is classifiedlaccording to wind power classes, which are based on typical wind speeds. These classes range from Class 1 (the lowest) to Class 7 (the highest). In general, at 50 meters, wind power Class 4 or higher can be useful for generating wind power with large turbines. Class 4 and above are considered good resources. Particular locations in the Class 3 areas could have higher wihd power class values at 80 meters than shown on the 50 meter map because of possible high wind shear. Given the advances in technology, a number of locations In the Class 3 areas may suitable for utility-scale wind development.

on Center Perspectives

. Resources & Tools L Wind Maps I

Software Publications '

News Events Past Events This map consistent wind resoi along the the higher Note: Win therefore, specific ar ndicates that North Carolina has wind resources with utility-scale production. The good-to-excellent irce areas are concentrated in two regions. The first is Atlantic coast and barrier islands. The second area is ridge crests in western North Carolina.

i resource at a micro level can vary significantly; you should get a professional evaluation of your ma of interest.

http://www.eere.energy.gov/windandhydro/windpoweringamericalmaps~template.asp?sta...

10/26/2005

H,,

I LATE-States Solar

('De ?-co b5 Page 1 of 2 States Byto q1

.0 C qe p;-,.o*.

F North Carolina Solar Resources The sun is a direct source of energy -

as anyone who has gotten a sunburn can attest.

Using renewable energy technologies can convert that solar energy into electricity, heating, and even cooling. But solar energy varies by location and by the time of year.

To give you a general idea of what solar resources are in your state, we are providing maps of the yearly average. The solar resources are expressed in watt-hours per square meter per day (Wh/m 2/day). Think of that as roughly a measure of how much energy falls on a square yard over the course of an average day.

These maps show the total solar energy falling on the Earth. Different solar technologies will convert that energy in different ways, and not all of that can be converted directly into useful energy. For reference, we will give you examples of what your state's resource means in terms of producing electricity.

It is interesting to remember that solar resources are greatest in the middle of the day -

the same time that utility customers have the highest demand, especially during the summer months.

[:Why Two Ma~ps?

7 North Carolina Solar Resource Flat-Plate Collector Flat-plate solar systems are, simply put, flat panels that collect sunlight and convert it to either electricity or heat. These technologies include photovoltaic (PV) arrays and solar water heaters. This map shows how much solar radiation reaches a flat-plate collector which is Installed in a tilted position, for example, on a roof.

A general rule of thumb is that a flat-plate collector gets the most sun if it is tilted towards the E

south at an angle equal to the latitude of the location.

Whrisq m per day a tI.=lo I.1.0 e i.SIOf oh

. 2400 to2-.5V0 a 26DW lo GS0O L;2 4XO10C.St4 r 6.oeI06MOse

• s.a~e~g

• &ouOOO6o What does the map mean?

Ebwto Mainly, it means that, for flat-Solar resource for a flatoate collector IR.

plate collectors, North Carolina has good, useful resources throughout the state. Let's say you installed a PV array with a collector area equal to the size of a football field. In one of your state's better locations, you http://www.eere.energy.gov/stateenergy/techsolar.cfin?state=NC 10/26/2005

ISt og r

e 1; -11,"ATATE - States Solar Page 2 of 2 would produce around 961,000 kWh per year. This is enough to power 96.4 average homes.

Because of their simplicity, flat-plate collectors are often used for residential and commercial building applications. They can also be used in large arrays for utility applications.

View a more detailed and current flat-plate collector solar map.

Solar Concentrator Solar concentrators are typically mounted on tracking systems in order to always face the sun.

This allows these collectors to capture the maximum amount of direct solar rays. The solar resource for concentrators varies much more across the United States than the flat-plate solar resource. Most northern states cannot use solar concentrators effectively, but this resource is even greater than the flat-plate resource in some areas of the southwestern United States.

Whrtaq m per day

• 2.OOO1o2520 a 2-Oto3,O O

• 3.aoootoga50 l a4s0 tocwo En 4.6 0 4o6O Li 4fM to

,MO ti 6_44)106¢w I em lo oRO The map shows that, for S

Z6007=0 concentrating collectors, North Slar resource fora concentrating collector Carolina could pursue some type of technologies, but thermal electricity systems are not effective with this resource. How much power would a concentrating system produce? Let's look at a current PV solar concentrator system with a collector area of 200,000 square meters -

a system that would cover roughly 200 acres. In the state's best areas, this system could produce about 34,215,000 kWh per year -

enough to power 3,433.5 homes.

Because these systems require tracking mechanisms, solar concentrators are generally used for large-scale applications such as utility or industrial use. But they can also be used in small-scale applications, including remote power applications.

States I

Technologies I

Policy Issues I

State contacts I

Home Webmaster I Security & Privacy I EERE Home U.S. Department of Energy Content Last Updated: 12 May 2005.

http://www.eere.energy.gov/state energy/tech solar.cfin?state=NC 10/26/2005

STATE - States Hydropower Page I of l States 'O Sta WAI

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.; 1July.

C North Carolina Hydropower Resources The amount of hydropower resource varies widely among states. To have a useable hydropower resource, a state must have both a large volume of flowing water and a significant change in elevation.

North Carolina has a moderate hydropower resource as a percentage of the state's electricity generation. North Carolina could produce an estimated 8,024,846 MWh of electricity annually from hydropower (see Figure 1). For comparison, this would represent 7% of the electricity generated from all sources in 1998 in North Carolina.

Hydropower Resource by State I

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The chart above shows the overall likely hydropower resource by state. This includes both current hydropower generation as well as an estimate of potential additional resources. This estimate factored in the many legal, social, and environmental constraints on hydropower development. For further information on these types of constraints, click here. For further information on the hydropower resources in the United States, visit the Web site of the U.S.

Department of Energy Hydropower Program.

States I

Technologies I

Policy Issues IState Contacts I

Home Webmaster I Security & Privacy I EERE Home U.S. Department of Energy Content Last Updated: 12 May 2005.

http://www.eere.energy.gov/stateenergy/techhydropower.cfm?state=NC 10/26/2005

STATE - States Geothermal Page I of 2 States I FM1 North Carolina Geothermal Resources Two types of geothermal resources are being tapped commercially: hydrothermal fluid resources and earth energy. Hydrothermal fluid resources (reservoirs of steam or very hot water) are well-suited for electricity generation. Earth energy, the heat contained in soil and rocks at shallow depths, is excellent for direct use and geothermal heat pumps. Direct-use applications require moderate temperatures; geothermal heat pumps can operate with low-temperature resources.

IEorectiJc o

tNW E] Gee. MmPumps North Carolina geothermal resource As indicated on the map, North Carolina has low-to-moderate-temperature resources that can be tapped for direct heat or for geothermal heat pumps. However, electricity generation is not possible with these resources.

Direct heat-resources can be used to provide heat in a variety of applications. The versatility and inexhaustibility of these resources make it attractive for municipalities as well as individuals and businesses. Geothermal heat pumps are similar to conventional air conditioners and refrigerators. But whereas air conditioners and refrigerators discharge waste heat to the air, geothermal heat pumps discharge waste heat to the ground during cooling season and extract useful heat from the ground during heating season. They are among the most efficient, and therefore least polluting, heating, cooling, and water-heating systems available.

States I

Technologies I

Policy Issues I

State Contacts I

Home Webmaster I Security & Privacy I EERE Home U.S. Department of Energy http://www.eere.energy.gov/stateenergy/techgeothermal.cefn?state=NC 10/26/2005

0i- +Municipal Solid Waste - MSW Disposal (E A 200Y's)

Page 1 of 2 U.S. Environmental Protection Agency Municipal Solid Waste Recent Additions I Contact Us I Print Version Search:

M EPA Home > Wases > Municipal Solid Waste > MSW Disposal Home Basic Facts Frequently Asked Questions Reduce, Reuse, and Recycle MSW Commodities MSW Disposal MSW Programs MSW State Data MSW Topics MSW Publications MSW Disposal Landfilling Although source reduction, reuse, recycling, and composting can divert large portions of municipal solid waste (MSW) from disposal, some waste still must be placed in landfills. Modem landfills are well-engineered facilities that are located, designed, operated, monitored, closed, cared for after closure, cleaned up when necessary, and financed to insure compliance with federal regulations. The federal regulations were established to protect human health and the environment. In addition, these new landfills can collect potentially harmful landfill gas emissions and convert the gas into energy.

• Landfill Publications

• Landfill Methane Outreach Program

• Landfill Regulations

• Landfill Air Emission Regulations and Air Models Combustion and Incineration To reduce waste volume, local governments or private operators can implement a controlled burning process called combustion or incineration. In addition to reducing volume, combustors, when properly equipped, can convert water into steam to fuel heating systems or generate electricity. Incineration facilities can also remove materials for recycling. Over one-fifth of the U.S. MSW incinerators use refuse derive fuel (RDF). In contrast to mass burning, where the MSW is introduced as is into the combustion chamber, RDF facilities are equipped to recover recyclables (e.g., metal cans and glass) first, then shred the combustible fraction into fluff for incineration.

Federal Landfill Standards

• Location restrictions ensure that landfills Ore builk in suitable geological areas away from faults, wetlands, flood plains, or other restricted areas.

• Liners are geomembrane or plastic sheets reinforced with two feet of clay on the bottom and sides of landfills.

• Operating practices such as compacting and covering waste frequently with several inches of soil help reduce odor; control litter, insects, and rodents; and protect public health.

• Groundwater monitoring requires testing groundwater wells to determine whether waste materials have escaped from the landfill.

• Closure and postclosure care include covering landfills and providing long-term care of closed landfills.

• Corrective action controls and cleans up landfill releases and achieves groundwater protection standards.

• Financial assurance provides funding for environmental protection during and after landfill closure (i.e.,

closure and postclosure care).

A variety of pollution control technologies significantly reduce the gases emitted into the I.

I

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Municipal Solid Waste - MSW Disposal Page 2 of 2 Benefits of Combustion Burning MSW can generate energy while reducing the amount of waste by up to 90 percent in volume and 75 percent in weight.

air. Among these are scrubbers -devices that use a liquid spray tb neutralize acid gases - and filters, which remove tiny ash particles. Burning waste at extremely high temperatures also destroys chemical compounds and disease-causing bacteria. Regular testing ensures that residual ash is non-hazardous before being landfilled. About ten percent of the total ash formed in the combustion process is utilized for beneficial use, primarily as daily cover in landfills and road-building aggregates.

• Combustion and Incineration Regulations lIxi1aimrf

• OAR's Electricity from MSW Common household items such as paints, cleaners, oils, batteries, and pesticides contain hazardous components. Leftover portions of these products are called household hazardous waste. These products, if mishandled, can be dangerous to your health and the environment.

• More About Household Hazardous Waste Back to top EPA Home I Pnvacv and Security Notice I Contact Us Last updated on Tuesday, May 24th, 2005 URL: http:/twww.epa.gov/epaoswer/non-hw/muncplldisposal.htm

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ta U.S. Department of Transportation Federal Aviation Administration (7-AA,ZCXC))

ADVISORY CIRCULAR AC 70/7460-1K Obstruction Marking and Lighting

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_1481 Effective: 8/1/00 Prepared by the Air Traffic Airspace Management

Ot ADVISORY U.S. Department CIRCULAR Of Transportation Federal Aviation Administration

Subject:

CHANGE 1 TO OBSTRUCTION Date: 4/15/00 AC No: 70/7460-IK MARKING AND LIGHTING Initiated by: ATA400 Change: 1

1. PURPOSE. This change amends the Federal Aviation Administration's (FAA) standards for marking and lighting structures to promote aviation safety. The Change Number and date of the change material are located at the top of the page.

2. EFFECTIVE DATE. This change is effective August 1, 2000.

3. EXPLANATION OF CHANGES.

a. Table of Contents. Change pages i through iii.

b. Change pages 19 through 32 beginning at Chapter 7. High Intensity Flashing White Obstruction Light Systems to read 21 through 34.

c. Page 1. Paragraph 1. Reporting Requirements. Owner changed to read sponsor.

d. Page 1. Paragraph 5. Modifications and Deviations. Owner changed to read sponsor.

e. Page 1. Paragraph 5.b.3. Voluntary Marking and/or Lighting. Ownerfs changed to read sponsor.

f. Page 2. Paragraph d. Chapter 6 changed to read Chapter 12, Table 4.

g. Page 2. Paragraph d. Owners/proponents changed to read sponsors.

h. Page 2. Paragraph 6. Additional Notification. Proponents changed to read sponsors.

i. Page 2. Paragraph 7. Metric Units. Proponents changed to read sponsors.

j. Page 3. Paragraph 23. Light Failure Notification. Proponents changed to read sponsors.

k. Page 4. Paragraph 24. Notification of Restoration. Owner changed to read sponsor.

1. Page 7. Note. Change proponents to read sponsors.

m. Page 11. Paragraph 49. Distraction. Owner changed to read sponsor

n. Replace Pages Al-I through Al-19. New illustrations. In addition, mid-level lighting on structures beginning at 250 feet above ground level (AGL) has been corrected to reflect lighting beginning at 350 feet AGL.

(4gOHN S. WALKER Program Director for Air Traffic Airspace Management

PAGE CONTROL CHART AC 70/7460-1K, CHG. 1 Remove Pages Dated Insert Pages Dated i through iii 1 through 4 7

11 Al-I through Al-19 3/1/00 3/1/00 3/1/00 3/1/00 3/1/00 i through iii 1 through 4 7

11 Al-M through Al-19 8/1/00 8/1/00 8/1/00 8/1/00 8/1/00

8/1/00 AC 7017460-1K CHG 1 Table of Contents CHAPTER 1. ADMINISTRATIVE AND GENERAL PROCEDURES

1. REPORTING REQUIREMENTS...

1

2. PRECONSTRUCTION NOTICE.1

3. FAA ACKNOWLEDGEMENT..1

4. SUPPLEMENTAL NOTICE REQUIREMENT.................................................................................................................1

5. MODIFICATIONS AND DEVIATIONS..1

6. ADDITIONAL NOTIFICATION

.2

7. METRIC UNITS

.2 CHAPTER 2. GENERAL

20. STRUCTURES TO BE MARKED AND LIGHTED.3

21. GUYED STRUCTURES..3

22. MARKING AND LIGHTING EQUIPMENT..3

23. LIGHT FAILURE NOTIFICATION..3

24. NOTIFICATION OF RESTORATION 4

25. FCC REQUIREMENT..4 CHAPTER 3. MARKING GUIDLINES

30. PURPOSE...............................................................................................................................................................................5

31. PAINT COLORS..5

32. PAINT STANDARDS..5

33. PAINT PATTERNS..5 34, MARKERS..6

35. UNUSUAL COMPLEXITIES..7

36. OMISSION OR ALTERNATIVES TO MARKING...

7 CHAPTER 4. LIGHTING GUIDELINE Anl 1PrDpn~r e

3 1. P A I N T O L O R S...........................................................................

41. STANDARDS

42. LIGHTING S

43. CATENARY

44. INSPECTIO1

45. NONSTAND,

46. PLACEMEN

47. MONITORI]

48. ICE SHIELD AG fTYTIP A (TIE 7

.. 9

.YSTEMS..9 LIGHTING............................................................................................................................

.......... 10 NJ, REPAIR AND MAINTENANCE....

10 ARDL LIGHTS...10 TFACTORS...

10 OBON L

S......

11

-7.

50.

51.

52.

53.

54.

55.

56.

57.

58.

And v An s svA....................................... *..............................................................................................................................

CHAPTER 5. RED OBSTRUCTION LIGHT SYSTEM PURPOSE......

_13 STANDARDS........

13 CONTROL DEVICE1...........13 POLES, TOWERS, AND SIMILAR SKELETAL STRUCTURES 13 CHIMNEYS, FLARE STACKS, AND SIMILAR SOLID STRUCTURES 14 WIND TURBINE STRUCTURES.14 GROUP OF OBSTRUCTIONS.14 ALTERNATE METHOD OF DISPLAYING OBSTRUCTION LIGHTS.15 PROMINENT BUILDINGS, BRIDGES, AND SIMILAR EXTENSIVE OBSTRUCTIONS.15 Table of Contents i

AC 70o7460-1K CHC 1 811100 CHAPTER 6. MEDIUM INTENSITY FLASHING WHITE OBSTRUCTION LIGHT SYSTEMS

60. PURPOSE 17

61. STANDARDS..................................

7

62. RADIO AND TELEVISION TOWERS AND SIMILAR SKELETAL STRUCTURES.

63. CONTROL DEVICE.....................................................................

17

64. CHIMNEYS, FLARE STACKS, AND SIMILAR SOLID STRUCTURES.................................................................18

65. WIND TURBINE STRUCTURES.....................................................................

18

66. GROUP OF OBSTRUCTIONS.....................................................................

18

67. SPECIAL CASES 18

68. PROMINENT BUILDINGS AND SIMILAR EXTENSIVE OBSTRUCTIONS.

18 CHAPTER 7. HIGH INTENSITY FLASHING WHITE OBSTRUCTION LIGHT SYSTEMS

70. PURPOSE...................................................................................2..............1......................................................................1...21

71. STANDARDS..........................

21

72. CONTROL DEVICE..........................

21

73. UNITS PER LEVEL 21

74. INSTALLATION GUIDANCE.............................................................................................................

......................... 21

75. ANTENNA OR SIMILAR APPURTENANCE LIGHT..........................................................

22

76. CHIMNEYS, FLARE STACKS, AND SIMILAR SOLID STRUCTURES..................................................................22

77. RADIO AND TELEVISION TOWERS AND SIMILAR SKELETAL STRUCTURES.

22

78. HYPERBOLIC COOLING TOWERS...............................................................

22

79. PROMINENT BUILDINGS AND SIMILAR EXTENSIVE OBSTRUCTIONS........................................................... 23 CHAPTER 8. DUAL LIGHTING WITH REDIMEDIUM INTENSITY FLASHING WHITE SYSTEMS

80. PURPOSE................................

25

81. INSTALLATION.............

25

82. OPERATION..................

25

83. CONTROL DEVICE...................

25

84. ANTENNA OR SIMILAR APPURTENANCE LIGHT 25

85. WIND TURBINE STRUCTURES.............................................

25

86. OMISSION OF MARKING.............................................

25 CHAPTER 9. DUAL LIGHTING WITH RED/HIGH INTENSITY FLASHING WHITE SYSTEMS

90. PURPOSE......................................................

27 99 S

A I

LLATION2........................................................................................................................... I......................................727

92. OPERATION...........................................

... 27

93. CONTROL DEVICE............................................

27

94. ANTENNA OR SIMILAR APPURTENANCE LIGHT.............................................

27

95. OMISSION OF MARKING..............................................................................................................................................27 CHAPTER 10. MARKING AND LIGHTING OF CATENARY AND CATENARY SUPPORT STRUCTURES 100. PURPOSE...........................................................-

101. CATENARY MARKING STANDARDS.......................................................................................................................29 102. CATENARY LIGHTING STANDARDS......................................................

29 103. CONTROL DEVICE.....................................................

30 104. AREA SURROUNDING CATENARY SUPPORT STRUCTURES.....................................................

, 30 105. THREE OR MORE CATENARY SUPPORT STRUCTURES......................................................

30 All Table of Contents

8/1/00 AC 70/7460-1K CHG 1 CHAPTER 11. MARKING AND LIGHTING MOORED BALLOONS AND KITES 110. PURPOSE............

31 111. STANDARDS.............

31 112. MARKING.

31 113. PURPOSE..........

31 114. OPERATIONAL CHARACTERISTICS.......................................................................................

31 CHAPTER 12. MARKING AND LIGHTING EQUIPMENT AND INFORMATION 120. PURPOSE........................................................................................

33 121. PAINT STANDARD........................................................................................

33 122. AVAILABILITY OF SPECIFICATIONS.......................................................................................

33 123. LIGHTS AND ASSOCIATED EQUIPMENT.......................................................................................

33 124. AVAILABILITY.......................................................................................

34 APPENDIX 1: SPECIFICATIONS FOR OBSTRUCTION LIGHTING EQUIPMENT CLASSIFICATION APPENDIX........

Al-l APPENDIX 2. MISCELLANEOUS

1. RATIONALE FOR OBSTRUCTION LIGHT INTENSITIES...................................................................................... A2-1

2. DISTANCE VERSUS INTENSITIES............................................................................................................D...................A2-1

3. CONCLUSION...............................................................................................................................I................................... A2-1

4. DEFINITIONS.-..................................................................................................................................................................4.

A2-1

5. LIGHTING SYSTEM CONFIGURATION..................................q A2-2 Table of Contents

d 8{1/00 AC 70/7460-IK CRG 1 8(1100 AC 7017460-1K CHG I CHAPTER 1. ADMINISTRATIVE AND GENERAL PROCEDURES I

1. REPORTING REQUIREMENTS A sponsor proposing any type of construction or alteration of a structure that may affect the National Airspace System (NAS) is required under the provisions of 14 Code of Federal Regulations (14 CFR part 77) to notify the FAA by completing the Notice of Proposed Construction or Alteration form (FAA Form 7460-1). The form should be sent to the FAA Regional Air Traffic Division offic& having jurisdiction over the area where the planned construction or alteration would be located. Copies of FAA Form 7460-1 may be obtained from any FAA Regional Air Traffic Division office, Airports District Office or FAA Website at www.faa.gov/ats/ata/ata400.

2. PRECONSTRUCTION NOTICE The notice must be submitted:

a. At least 30 days prior to the date of proposed construction or alteration is to begin.

b. On or before the date an application for a construction permit is filed with the Federal Communications Commission (FCC).

(The FCC advises its applicants to file with the FAA well in advance of the 30-day period in order to expedite FCC processing.)

3. FAA ACKNOWLEDGEMENT The FAA will acknowledge, in writing, receipt of each FAA Form 7460-1 notice received.

4. SUPPLEMENTAL NOTICE REQUIREMENT

a. If required, the FAA will include a FAA Form 7460-2, Notice of Actual Construction or Alteration, with a determination.

b. FAA Form 7460-2 Part I is to be completed and sent to the FAA at least 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> prior to starting the actual construction or alteration of a structure.

Additionally, Part 2 shall be submitted no later than 5 days after the structure has reached its greatest height. The form should be sent to the Regional Air Traffic Division office having jurisdiction over the area where the construction or alteration would be located.

c. In addition, supplemental notice shall be submitted upon abandonment of construction.

d. Letters are acceptable in cases where the construction/alteration is temporary or a proposal is abandoned., This notification process is designed to permit the FAA the necessary time to change affected procedures and/or minimum flight altitudes, and to otherwise alert airmen of the structure's presence.

Note-NOTIFICATIONAS REQUIRED IN THE DETERMINATIONIS CRITICAL TOAVIA TION SAFETY

5. MODIFICATIONS AND DEVIATIONS

a. Requests for modification or deviation from the standards outlined in this AC must be submitted to the FAA Regional Air Traffic Division office serving the area where the structure would be located. The sponsor is responsible for adhering to approved marking and/or lighting limitations, and/or recommendations given, and should notify the FAA and FCC (for those structures regulated by the FCC) prior to removal of marking -and/or lighting.

A request received after a determination is issued may require a new study and could result in a new determination.

b. Modifications. Modifications will be based on whether or not they impact aviation safety. Examples of modifications that may be considered:

1. Marking and/or Lighting Only a Portion of an Object. The object may be so located with respect to other objects or terrain that only a portion of it needs to be marked or lighted.

2. No Marking and/or Lighting.

The object may be so located with respect to other objects or terrain, removed from the general flow of air traffic, or may be so conspicuous by its shape, size, or color that marking or lighting would serve no useful purpose.

3. Voluntary Marking and/or Lighting. The object may be so located with respect to other objects or terrain that the sponsor feels increased conspicuity would better serve aviation safety. Sponsors who desire to voluntarily mark and/or light their structure should request the proper marking and/or lighting from the FAA to ensure no aviation safety issues are impacted.

4.

Marking or Lighting an Object in Accordance with the Standards for an Object of Greater Height or Size. The object may present such an extraordinary hazard potential that higher standards may be recommended for increased conspicuity to ensure the safety to air navigation.

c. Deviations. The FAA regional office conducts an aeronautical study of the proposed deviation(s)

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8/1/00 AC 70/ 7460-IK CHG I 8/1/00 AC 70/7460-1K CHG I I

I and forwards its recommendation to FAA headquarters in Washington, DC, for final approval.

Examples of deviations that may be considered:

1. Colors of objects.

2. Dimensions of color bands or rectangles.

3. Colors/types of lights.

4. Basic signals and intensity of lighting.

5. Night/day lighting combinations.

6. Flash rate.

d. The FAA strongly recommends that sponsors become familiar with the different types of lighting systems and to specifically request the type of lighting system desired when submitting FAA Form 7460-1. (This request should be noted in "item 2.D" of the FAA form.) Information on these systems can be found in Chapter 12, Table 4 of this AC. While the FAA will make every effort to accommodate the request, sponsors should also request information from system manufacturers. In order to determine which system best meets their needs based on purpose, installation, and maintenance costs.

6. ADDITIONAL NOTIFICATION Sponsors are reminded that any change to the submitted information on which the FAA has based its determination, including modification, deviation or optional upgrade to white lighting on structures which are regulated by the FCC, must also be filed with the FCC prior to making the change for proper authorization and annotations of obstruction marlding and lighting.

These structures will be subject to inspection and enforcement of marking and lighting requirements by the FCC. FCC Forms and Bulletins can be obtained from the FCC's National Call Center at 1-888-CALL-FCC (1-888-225-5322).

Upon completion of the actual

change, notify the Aeronautical Charting office at:

NOAA/NOS Aeronautical Charting Division Station 5601, N/ACCI 13 1305 East-West Highway Silver Spring, MD 20910-3233

7. METRIC UNITS To promote an orderly transition to metric units, sponsors should include both English and metric (SI units) dimensions. The metric conversions may not be exact equivalents, and until there is an official changeover to the metric system, the English dimensions will govern.

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8l/OO0 AC 70/7460-IK COG I 8/1/00 AC 70/7460-1K CHG 1 CHAPTER2.GENERAL

20. STRUCTURES TO BE MARKED AND LIGHTED Any temporary or permanent structure, including all appurtenances, that exceeds an overall height of 200 feet (61m) above ground level (AGL) or exceeds any obstruction standard contained in 14 CFR part 77, should normally be marked and/or lighted. However, an FAA aeronautical study may reveal that the absence of marking and/or lighting will not impair aviation safety. Conversely, the object may present such an extraordinary hazard potential that higher standards may be recommended for increased conspicuity to ensure safety to air navigation.

-Normally outside commercial lighting is not considered sufficient reason to omit recommended marking and/or lighting.

Recommendations on marking and/or lighting structures can vary depending on terrain features, weather patterns, geographic location, and in the case of wind turbines, number of structures and overall layout of design.

The FAA may also recommend marking and/or lighting a structure that does not exceed 200 (61m) feet AGL or 14 CFR part 77 standards because of its particular location.

21.

GUYED STRUCTURES The guys of a 2,000-foot (610m) skeletal tower are anchored from 1,600 feet (488m) to 2,000 feet (61 Om) from the base of the structure. This places a portion of the guys 1,500 feet (458m) from the tower at a height of between 125 feet (38m) to 500 feet (153m) AGL. 14 CFR part 91, section 119, requires pilots, when operating over other than congested areas, to remain at least 500 feet (153m) from man-made structures.

Therefore, the tower must be cleared by 2,000 feet (61 Om) horizontally to avoid all guy wires. Properly maintained marking and lighting are important for increased conspicuity since the guys of a structure are difficult to see until aircraft are dangerously close.

22. MARKING AND LIGHTING EQUIPMENT Considerable effort and research have been expended in determining the minimum marking and lighting systems or quality of materials that will produce an acceptable level of safety to air navigation. The FAA will recommend the use of only those marking and lighting systems that meet established technical standards. While additional lights may be desirable to identify an obstruction to air navigation and may, on occasion be recommended, the FAA will recommend minimum standards in the interest of safety, economy, and related concerns. Therefore, to provide an adequate level of safety, obstruction lighting systems should be installed, operated, and maintained in accordance with the recommended standards herein.

23. LIGHT FAILURE NOTIFICATION

a. Sponsors should keep in mind that conspicuity is achieved only when all recommended lights are working.

Partial equipment outages decrease the margin of safety. Any outage should be corrected as soon as possible. Failure of a steady burning side or intermediate light should be corrected as soon as possible, but notification is not required.

b. Any failure or malfunction that lasts more than thirty (30) minutes and affects a top light or flashing obstruction light, regardless of its position, should be reported immediately to the nearest flight service station (FSS) so a Notice to Airmen (NOTAM) can be issued. Toll-free numbers for FSS are listed in most telephone books or on the FAA's Website at www.faa.gov/ats/ata/ata400.

This report should contain the following information:

1. Name of persons or organizations reporting light failures including any title, address, and telephone number.

2. The type of structure.

3. Location of structure (including latitude and longitude, if known, prominent structures, landmarks, etc.).

4. Height of structure above ground level (AGL)/above mean sea level (AMSL), if known.

5. A return to service date.

6. FCC Antenna Registration Number (for structures that are regulated by the FCC).

Note-

1. When the primary lamp in a double obstruction light fails, and the secondary lamp comes on, no report is required. However, when one of the lamps in an incandescent L-864 flashing red beacon fails. it should be reported

2. After 15 days, the NOTAM is automatically deleted from the system.

The sponsor is requested to call the nearest FSS to extend the outage date. In addition, the sponsor is required to report a return to service date.

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24. NOTIFICATION OF RESTORATION As soon as normal operation is restored, notify the same AFSS/FSS that received the notification of failure. The FCC advises that noncompliance with notification procedures could subject its sponsor to penalties or monetary forfeitures.

25. FCC REQUIREMENT FCC licensees are required to file an environmental assessment with the Commission when seeking authorization for the use of the high intensity flashing white lighting system on structures located in residential neighborhoods, as defined by the applicable zoning law.

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Chap 2

311100 AC 70/7460-IK 311100 AC 7017460-1K CHAPTER 3. MARKING GUIDLINES

30. PURPOSE This chapter provides recommended guidelines to make certain structures conspicuous to pilots during daylight hours.

One way of achieving this conspicuity is by painting and/or marking these structures. Recommendations on marking structures can vary depending on terrain features, weather patterns, geographic location, and in the case of wind turbines, number of structures and overall layout of design.

31. PAINT COLORS Alternate sections of aviation orange and white paint should be used as they provide maximum visibility of an obstruction by contrast in colors.

32. PAINT STANDARDS The following standards should be followed. To be effective, the paint used should meet specific color requirements when freshly applied to a structure.

Since, all outdoor paints deteriorate with time and it is not practical to give a maintenance schedule for all climates, surfaces should be repainted when the color changes noticeably or its effectiveness is reduced by

scaling, oxidation,

chipping, or layers of contamination.

a. Materials and Application. Quality paint and materials should be selected to provide extra years of service. The paint should be compatible with the surfaces to be painted, including any previous

coatings, and suitable for the environmental conditions. Surface preparation and paint application should be in accordance with manufacturer's recommendations.

Note-In-Service Aviation Orange Color Tolerance Charts are availablefrom private suppliers for determining when repainting is required The color should be sampled on the tipper hay!of the structure, since weathering is greater there.

b. Surfaces Not Requiring Paint. Ladders, decks, and walkways of steel towers and similar structures need not be painted if a smooth surface presents a potential hazard to maintenance personnel.

Paint may also be omitted from precision or critical surfaces if it would have an adverse effect on the transmission or radiation characteristics of a signal.

However, the overall marking effect of the structure should not be reduced.

c.

Skeletal Structures.

Complete all marking/painting prior to or immediately upon completion of construction. This applies to catenary support structures, radio and television towers, and similar skeletal structures.

To be effective, paint should be applied to all inner and outer surfaces of the framework.

33. PAINT PATTERNS Paint patterns of various types are used to mark structures. The pattern to be used is determined by the size and shape of the structure. The following patterns are recommended.

a. Solid Pattern. Obstacles should be colored aviation orange if the structure has both horizontal and vertical dimensions not exceeding 10.5 feet (3.2m).

b. Checkerboard Pattern. Alternating rectangles of aviation orange and white are normally displayed on the following structures:

1. Water, gas, and grain storage tanks.

2. Buildings, as required.

3. Large structures exceeding 10.5 feet (3.2m) across having a horizontal dimension that is equal to or greater than the vertical dimension.

c. Size of Patterns. Sides of the checkerboard pattern should measure not less. than 5 feet (1.5m) or more than 20 feet (6m) and should be as nearly square as possible.

However, if it is impractical because of the size or shape of a structure, the patterns may have sides less than 5 feet (1.5m).

When possible, corner surfaces should be colored orange.

d. Alternate Bands. Alternate bands of aviation orange and white are normally displayed on the following structures:

1. Communication towers and catenary support structures.

2. Poles.

3. Smokestacks.

4. Skeletal framework of storage tanks and similar structures.

5. Structures which appear narrow from a side view, that are 10.5 feet (3.2m) or more across and the horizontal dimension is less than the vertical dimension.

6. Wind turbine generator support structures including the nacelle or generator housing; Chap 3 5

I p1 3/1/00 AC 70/7460-1K

7. Coaxial cable, conduits, and other cables attached to the face of a tower.

e. Color Band Characteristics.

Bands for structures of any height should be:

1. Equal in width, provided each band is not less than 11/2 feet (0.5m) or more than 100 feet (31m) wide.

2. Perpendicular to the vertical axis with the bands at the top and bottom ends colored orange.

3. An odd number of bands on the structure.

4. Approximately one-seventh the height if the structure is 700 feet (214m) AGL or less. For each additional 200 feet (61m) or fraction thereof, add one (1) additional orange and one (1) additional white band.

5. Equal and in proportion to the structure's height AGL.

Structure Height to Bandwidth Ratio Example: If a Structure is:

Greater Than But Not More Band Width Than 10.5 feet 700 feet 1/7 of height (3.2m)

(214m)

___ofheight 701 feet 900 feet

/9 of height (214m)

(275m) 901 feet 1,100 feet Xhi of height (275m)

(336m)

____of_______

1,100 feet 1,300 feet 1/13 of height (336m)

( 9 m structure.

A minimum of three bands should be displayed on the upper portion of the structure.

L Teardrop Pattern. Spherical water storage tanks with a single circular standpipe support may be marked in a teardrop-striped pattern. The tank should show alternate stripes of aviation orange and white.

The stripes should extend from the top center of the tank to its supporting standpipe. The width of the stripes should be equal, and the width of each stripe at the greatest girth of the tank should not be less than 5 feet (1.5m) nor more than 15 feet (4.6m).

j. Community Names. If it is desirable to paint the name of the community on the side of a tank, the stripe pattern may be broken to serve this purpose.

This open area should have a maximum height of 3 feet (0.9m).

k Exceptions. Structural designs not conducive to standard markings may be marked as follows:

1. If it is not practical to color the roof of a structure in a checkerboard pattern, it may be colored solid orange.

2. If a spherical structure is not suitable for an exact checkerboard pattern, the shape of the rectangles may be modified to fit the shape of the surface.

3. Storage tanks not suitable for a checkerboard pattern may be colored by alternating bands of aviation orange and white or a limited checkerboard pattern applied to the upper one-third of the structure.

4. The skeletal framework of certain water, gas, and grain storage tanks may be excluded from the checkerboard pattern.

34. MARKERS Markers are used to highlight structures when it is impractical to make them conspicuous by painting.

Markers may also be used in addition to aviation orange and white paint when additional conspicuity is necessary for aviation safety.

They should be displayed in conspicuous positions on or adjacent to the structures so as to retain the general definition of the structure. They should be recognizable in clear air from a distance of at least 4,000 feet (1219m) and in all directions from which aircraft are likely to approach. Markers should be distinctively shaped, i.e., spherical or cylindrical, so they are not mistaken for items that are used to convey other information.

They should be replaced when faded or otherwise deteriorated.

TBL I If the f Structures With a Cover or Roof structure has a cover or roof, the highest orange band should be continued to cover the entire top of the structure.

g. Skeletal Structures Atop Buildings.

If a flagpole, skeletal structure, or similar object is erected on top of a building, the combined height of the object and building will determine whether marking is recommended; however, only the height of the object under study determines the width of the color bands.

h. Partial Marking. If marking is recommended for only a portion of a structure because of shielding by other objects or terrain, the width of the bands should be determined by the overall height of the 6

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a. Spherical Markers. Spherical markers are used to identify overhead wires. Markers may be of another shape, i.e., cylindrical, provided the projected area of such markers will not be less than that presented by a spherical marker.

1. Size and Color.

The diameter of the markers used on extensive catenary wires across canyons, lakes, rivers, etc.,

should be not less than 36 inches (91cm). Smaller 20-inch (51 cm) spheres are permitted on less extensive power lines or on power lines below 50 feet (15m) above the ground and within 1,500 feet (458m) of an airport runway end. Each marker should be a solid color such as aviation orange, white, or yellow.

2. Installations.

(a) Spacing.

Markers should be spaced equally along the wire at intervals of approximately 200 feet (61m) or a fraction thereof.

Intervals between markers should be less in critical areas near runway ends (i.e., 30 to 50 feet (lOm to 15m)). They should be displayed on the highest wire or by another means at the same height as the highest wire. Where there is more than one wire at the highest point, the markers may be installed alternately along each wire if the distance between adjacent markers meets the spacing standard. This method allows the weight and wind loading factors to be distributed.

(b) Pattern.

An alternating color scheme provides the most conspicuity against all backgrounds.

Mark overhead wires by alternating solid colored markers of aviation orange, white, and yellow. Normally, an orange sphere is placed at each end of a line and the spacing is adjusted (not to exceed 200 feet (61m)) to accommodate the rest of the markers. When less than four markers are used, they should all be aviation orange.

b. Flag Markers. Flags are used to mark certain structures or objects when it is technically impractical to use spherical markers or painting. Some examples are temporary construction equipment,

cranes, derricks, oil and other drilling rigs.

Catenaries should use spherical markers.

1. Minimum Size. Each side of the flag marker should be at least 2 feet (0.6m) in length.

2. Color Patterns. Flags should be colored as follows:

(a) Solid. Aviation orange.

(b) Orange and White.

Arrange two triangular sections, one aviation orange and the other white to form a rectangle.

(c) Checkerboard Flags 3 feet (0.9m) or larger should be a checkerboard pattern of aviation orange and white squares, each I foot (0.3m) plus or minus 10 percent.

3. Shape. Flags should be rectangular in shape and have stiffeners to keep them from drooping in calm wind.

4. Display. Flag markers should be displayed around, on top, or along the highest edge of the obstruction. When flags are used to mark extensive or closely grouped obstructions, they should be displayed approximately 50 feet (1Sm) apart. The flag stakes should be of such strength and height that they will support the flags above all surrounding ground, structures, and/or objects of natural growth.

35. UNUSUAL COMPLEXITIES The FAA may also recommend appropriate marking in an area where obstructions are so grouped as to present a common obstruction to air navigation.

36. OMISSION OR ALTERNATIVES TO MARKING There are two alternatives to marking. Either alternative requires FAA review and concurrence.

a. High Intensity Flashing White Lighting Systems.

The high intensity lighting systems are more effective than aviation orange and white paint and therefore can be recommended instead of marking.

This is particularly true under certain ambient light conditions involving the position of the sun relative to the direction of flight. When high intensity lighting systems are operated during daytime and twilight, other methods of marking may be omitted.

When operated 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> a day, other methods of marking and lighting may be omitted.

b. Medium Intensity Flashing White Lighting Systems. When medium intensity lighting systems are operated during daytime and twilight on structures 500 feet (153m) AGL or less, other methods of marking may be omitted. When operated 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> a day on structures 500 feet (153m) AGL or less, other methods of marking and lighting may be omitted.

Note-SPONSORS MUST ENSURE THAT ALTERNATIVES TOMAURMN ARE COORDINATED WITH THE FCC FOR STRUCTURES UNDER ITS JURISDICTION PRIOR TO MAKING THE CHANGE.

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6 3/11/00 AC 70/7460-4K zmffimnlaw
_i CHAPTER 4. LIGHTING GUIDELINE

40. PURPOSE This chapter describes the various obstruction lighting systems used to identify structures that an aeronautical study has determined will require added conspicuity.

The lighting standards in this circular are the minimum necessary for aviation safety.

Recommendations on lighting structures can vary depending on terrain features, weather patterns, geographic location, and in the case of wind turbines, number of structures and overall layout of design.

41. STANDARDS The standards outlined in this AC are based on the use of light units that meet specified intensities, beam patterns, color, and flash rates as specified in AC 150/5345-43.

These standards may be obtained from:

Department of Transportation TASC Subsequent Distribution Office, SVC-121.23 Ardmore East Business Center 3341 Q 75th Avenue Landover, MD 20785 This system should not be recommended on structures 500 feet (153m) AGL orless, unless an FAA aeronautical study shows otherwise.

Note-Allflashing lights on a structure shouldflash simultaneously exceptfor catenary support structures, which have a distinct sequence flashing between levels.

d. Dual Lighting. This -system consists of red lights for nighttime and high or medium intensity flashing white lights for daytime and twilight. When a dual lighting system incorporates medium flashing intensity lights on structures 500 feet (153m) or less, or high intensity flashing white lights on structures of any height, other methods of marking the structure may be omitted.

e. Obstruction Lights During Construction. As the height of the structure exceeds each level at which permanent obstruction lights would be recommended, two or more lights of the type specified in the determination should be installed at that level.

Temporary high or medium intensity flashing white lights, as recommended in the determination, should be operated 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> a day until all permanent lights are in operation. In either case, two or more lights should be installed on the uppermost part of the structure any time it exceeds the height of the temporary construction equipment.

They may be turned off for periods when they would interfere with construction personnel.

If practical, permanent obstruction lights should be installed and operated at each level as construction progresses.

The lights should be positioned to ensure that a pilot has an unobstructed view of at least one light at each level.

f. Obstruction Lights in Urban Areas. When a structure is located in an urban area where there are numerous other white lights (e.g., streetlights, etc.)

red obstruction lights with painting or a medium intensity dual system is recommended.

Medium intensity lighting is not normally recommended on structures less than 200 feet (61m).

g. Temporary Construction Equipbment Lighting.

Since there is such a variance in construction cranes, derricks, oil and other drilling rigs, each case should be considered individually.

Lights should be installed according to the standards given in Chapters 5, 6, 7, or 8, as they would apply to permanent structures.

42. LIGHTING SYSTEMS Obstruction lighting may be displayed on structures as follows:

a. Aviation Red Obstruction Lights. Use flashing beacons and/or steady burning lights during nighttime.

b. Medium Intensity Flashing White Obstruction Lights. Medium intensity flashing white obstruction lights may be used during daytime and twilight with automatically selected reduced intensity for nighttime operation. When this system is used on structures 500 feet (153m) AGL or less in height, other methods of marking and lighting the structure may be omitted.

Aviation orange and white paint is always required for daytime marking on structures exceeding 500 feet (153m) AGL.

This system is not normally recommended on structures 200 feet (61m) AGL or less.

c. High Intensity Flashing White Obstruction Lights. Use high intensity flashing white obstruction lights during daytime with automatically selected reduced intensities for twilight and nighttime operations. When this system is used, other methods of marking and lighting the structure may be omitted.

Chap 4 9