plants were built in NC Power's territory in the early to mid-1990 s (324.5 MW of coal and 165 MW of natural gas).

Transcription

1 III. OTHER FUELS The Commission s Order requesting the Public Staff to investigate the availability and adequacy of the infrastructure in North Carolina to support future electric generation included a consideration of the availability of fuels in addition to natural gas. This chapter discusses three additional fuels for the generation of electricity: renewable fuel, coal, and nuclear fuel. North Carolina s investor-owned utilities have traditionally met customer demand by constructing their own generating plants fueled by coal, nuclear fuel, oil and natural gas, and water. Another source of the electricity the utilities use to meet the demands of their customers is purchases from nonutility generators. Currently nonutility generation (not including generation owned and used by an end use customer for itself) constitutes less than ten percent of the capacity in operation in North Carolina. Nonutility generation, other than customer-owned self-generation, was rare prior to the passage of the Public Utility Regulatory Policies Act of 1978 (PURPA). Section 210 of PURPA requires utilities to purchase electricity at avoided cost rates from generating facilities that qualify under PURPA, which includes (1) plants fueled by renewable fuels, such as solar, wind, water, methane, and animal waste; and (2) cogeneration plants, which typically use part of the steam associated with the generation process for industrial process purposes, rather than it being wasted. North Carolina separately encouraged the development of small hydroelectric generating facilities by enacting legislation to encourage their development by nonutilities. As a result of this encouragement, numerous small hydroelectric qualifying facilities came into existence in the early 1980 s at existing dams. In addition, a few landfill gas and biomass qualifying facilities were developed. With respect to cogeneration, five coal-fired plants were built in CP&L s territory during the mid-1980 s (266 MW), one coal-fired plant was built in Duke s territory, also in the mid-1980 s (52 MW purchase from an 80 MW plant), and three coal-fired and one natural gas-fired 3-1

2 plants were built in NC Power's territory in the early to mid-1990 s (324.5 MW of coal and 165 MW of natural gas). In recent years, nonqualifying facilities, initially called nonutility generators (NUGs) or independent power producers (IPPs), have become very active. They are now often called "merchant plants, although initially this label was applied only to a plant that had no contract to sell its output in place at the time it is constructed. These types of plants often qualify as Exempt Wholesale Generators (EWGs), which gives them special treatment under federal law. Nonutility plants located in North Carolina selling under contract to North Carolina utilities are as follows: Dynegy s Rockingham Power natural gas-fired CT plant of 800 MW, which is under contract to sell to 600 MW to Duke for a total of 8.5 years if Duke renews its options, with Duke having first call on the other 200 MW under limited circumstances, and the two of the coal-fired cogeneration plants referenced above selling under long-term contracts to NC Power have given up their qualifying status and now are EWGs. In South Carolina, Calpine s Broad River facility, which is an 800 MW gas-fired CT plant, sells its output to CP&L under a long-term contract. In addition, the utilities make a minimal amount of purchases from plants located outside of their control areas, some utility-owned and some nonutility-owned. According to the Annual Report of the North Carolina Utilities Commission Regarding Long Range Needs for Expansion of Electric Generation Facilities for Service in North Carolina, July 2002 (2002 Annual Report), the current capacity mix of each of the utilities is as follows: Annual Report, p

3 Installed Generating Capacity (MW) by Fuel Type (Summer) for Fuel Type CP&L Duke NC Power Coal 44%* 40% 37% Nuclear 26%* 36%* 24% Hydroelectric 2% 15% 11% Oil & Natural Gas 28% 9% 28% * Includes the plants they jointly own with various public power entities. Also according to the 2002 Annual Report, the actual generation mix (MWh generated) for each utility is as follows: 3 Energy Resources (MWh) by Fuel Type for 2001 Fuel Type CP&L Duke NC Power Coal 50.1%* 48.7% 41.3% Nuclear 38.4% * 47.8%* 32.0% Hydroelectric 0.4% 0.0% 3.8% Oil & Natural Gas 1.6% 0.1% 8.9% Purchased Power 9.5% 3.4% 14.0% *Includes the MWh from the plants they jointly own with various public power entities. 2 All generation that is owned by the utilities and located within their control areas is included. For Duke and CP&L, it includes generation in each of their control areas in both North and South Carolina. For NC Power, it includes generation located predominantly in Virginia Annual Report, p

4 The generation mix of CP&L and Duke in terms of MW and MWh appear in the following table: GENERATION MIX OF CP&L AND DUKE Generation Mix in MW: CP&L 4 DUKE 5 Coal 5,285 7,699 Nuclear 3,174 6,996 CT 3,279 1,851 Combined Cycle 84 0 Hydro-Conventional 218 1,129 Pumped Storage Hydro 0 1,675 Total (MW) 12,040 19,350** Generation Mix in MWh (12 months ending December 31, 2001): CP&L 6 DUKE 7 Coal 27,823,518 41,795,486 Oil 256,463 84,137 Gas 635,172 55,033 Total Fossil 28,715,153 41,934,656 Nuclear 21,321,474 39,922,369 Hydro-Conventional 245, ,770 Pumped Storage Hydro 00 (752,174) Total Hydro 245,249 Total (MWh) 50,281,876* 98,022,847 Minus Catawba Owners 15,168,570 Duke Total 82,854,277 4 The MW amounts for CP&L for coal and nuclear include the plants jointly owned by the North Carolina Eastern Municipal Power Agency (NCEMPA), which owns 211 MW of coal-fired generation and MW of nuclear generation. 5 Total MW for Duke include the ownership interests of NCEMC, the Saluda River Electric Cooperative, Inc., North Carolina Municipal Power Agency No. 1, and Piedmont Municipal Power Agency in the Catawba nuclear plant. Duke's peak load forecast includes the loads of these joint owners associated with their ownership shares. 6 CP&L's total is net of NCEMPA's share of the energy from the four plants (five units) owned by both CP&L and NCEMPA. 7 Duke s fuel reports subtract the Catawba joint owners shares of Catawba s energy after all energy produced has been totaled. 3-4

5 The Southeastern Association of Regulatory Utility Commissioners recently published report assessing infrastructure in the Southeast, dated April 22, 2002 ( Southeastern Infrastructure Assessment ), states that SERC had combined summer capacity of over 171,000 MW in SERC s summer capacity mix by fuel type for 2001 is as follows: SERC MW Coal 41.3% Nuclear 18.3% Hydroelectric 7.3% Oil & Natural Gas 13.6%* Fossil Steam 10.2%** Pumped Storage 3.6% Other 2.4% Firm Capacity Interchange 3.2% * These are listed as combustion turbine and combined cycle and are assumed to be oil and gas-fired. ** The specific fuel source for this category is not listed. SERC is made up of four subregions: Entergy, Southern, the Tennessee Valley Authority (TVA) and VACAR. The Southeastern Infrastructure Assessment states that the VACAR subregion, which includes Virginia and the two Carolinas, is the largest of the subregions, with existing capacity of over 62,000 MW. (The summer capacity of the remaining subregions are as follows: Entergy has 27,700 MW, Southern has 48,000 MW, and TVA has 33,000 MW.) VACAR s summer capacity (MW) mix by fuel type for 2001 is as follows: VACAR MW Coal 38.9% Nuclear 22.9% Hydroelectric 5.8% Oil & Natural Gas 15.1% Fossil Steam 2.9% Pumped Storage 5.6% Other 6.6% Firm Capacity Interchange 2.2% 3-5

6 The EIA reports the following generation mix (by MWh) for the United States as a whole by fuel type for 2000 as follows: United States - MWh Coal 52% Nuclear 20% Hydroelectric 7% Oil & Natural Gas 19% Other Renewables 2% The use of fuels other than natural gas for the generation of electricity is discussed in the sections that follow. First, the use of renewable fuels, including conventional hydroelectric plants, in the United States as a whole and then in North Carolina, is discussed, as well as costs and projections as to future use. Then in separate sections that follow, coal and nuclear fuel are discussed, in terms of their use in the United States as a whole and in North Carolina, as well as their costs and related issues and projections as to future use. A. RENEWABLES Other than conventional hydroelectric generation, the impetus behind the development of most renewable generation was PURPA, which, in part, requires utilities to buy electricity from qualifying generating facilities. One type of qualifying facility (QF) established by PURPA is a "small power production facility," which is defined as a facility that produces electric energy solely by the use, as a primary energy source, of biomass, waste, renewable resources, geothermal resources, or any combination thereof; has a capacity not greater than 80 MW; and is not owned by a person engaged in the production or sale of electricity from other types of facilities. 16 U.S.C.A. 796(17)(A). The relevant sections of PURPA require the FERC to adopt rules that require electric utilities to offer to purchase electricity from QFs at avoided cost rates and for States to implement such rules. 3-6

7 Renewable generating facilities typically include those fueled by the sun, wind, water, landfill gas, animal waste, municipal solid waste, and wood waste. For purposes of North Carolina law, G.S. 62-3(27a), a small power producer is limited to a hydroelectric facility of no more than 80 MW in size that is not owned by a person primarily engaged in the production or sale of electricity from other types of facilities. Other than conventional hydroelectric generation, renewable energy does not now make up a significant percentage of total generation in either the United States as a whole or in North Carolina. The current and projected status of renewable energy is discussed below, first on a national basis and then specifically in North Carolina. 1. UNITED STATES The EIA projects that renewable fuel consumption, including ethanol for gasoline blending, will increase at an average rate of 1.7 percent per year through However, the use of renewable fuels for electric generation is projected to grow slowly because of the relatively low costs of fossil-fired generation and because competitive electricity markets favor less capital-intensive natural gas technologies over coal and base load renewables. Generation from renewables is expected to increase by 1.3 percent per year. 8 It is expected to remain approximately nine percent of total generation, including cogeneration and distributed generation, through Conventional hydroelectric power is expected to remain fairly constant from 2000 to 2020, mainly because of environmental limitations. It is expected to constitute six percent of total generation in Generation from nonhydroelectric renewable energy sources is projected to increase from two percent of both total generation and electricity sales to three percent 8 9 The EIA s Annual Energy Outlook Id., at p

8 of both. The largest source of nonhydroelectric renewable generation is biomass, mainly from cogeneration and co-firing in coal-fired plants. It is expected to increase from 38 billion kwh in 2000 to 64 billion kwh in Significant increases are projected for both geothermal and wind capacity and energy. Geothermal capacity is expected to increase by 87 percent to five GW and to provide 35 billion kwh of generation (one percent of total supply) in Wind power capacity is expected to increase by nearly 300 percent to four GW in 2010 and to nine GW in 2020, with energy production increasing from five billion kwh in 2000 to 24 billion in Municipal solid waste, including both firing with solid waste and use of landfill gas, also is projected to increase. Solar technologies are not expected to make significant contributions through The chart that follows shows the generation by renewable energy sources for 2000 with projections for 2010 and Figure 6 Projected Increases in Nonhydroelectric Renewable Electricity Generation by Energy Source for 2010 and 2020 (Billion kwh) 10 Id. 3-8

9 In developing its estimates, the EIA assumed that State mandates will require total additions of 7,035 MW of central station renewable generating capacity from 2000 to This includes 5,129 MW of wind capacity, 969 MW of landfill gas capacity, 390 MW of biomass capacity, 516 MW of geothermal capacity, and 31 MW of solar (photovoltaic and thermal). 11 The chart that follows shows projected capacity additions by type of renewable source. Figure 7 Projected Additions of Renewable Generating Capacity by Type, (MW) Estimates available from State implementation plans include new renewable capacity resulting from commercial builds, renewable portfolio standards, systems benefits charges, and other mandates. States with renewable fuel mandates or portfolio standards that project significant capacity additions include Texas (2,279 MW), California (1,930 MW), Nevada (1,148 MW), and New Jersey (904 MW). Smaller amounts are projected for Massachusetts, Minnesota, Iowa, Wisconsin and Arizona. 11 Id., at p

10 2. NORTH CAROLINA (a) Utility-Owned Hydroelectric Facilities According to CP&L s September 2001 Resource Plan, CP&L has total hydroelectric capacity of 218 MW. This capacity is made up of the following plants: Blewett (25 MW), Marshall (5 MW), Tillery (86 MW), and Walters (105 MW). Walters was recently relicensed. Duke s September 2001 Annual Plan indicates that Duke (including Nantahala) has 1,129 MW of conventional hydroelectric generation. In addition, it has 610 MW of pumped storage at its Jocassee plant and 1,065 MW at its Bad Creek plant. Nantahala has filed notices of intent to relicense for eight hydroelectric projects, three of which include multiple sites. Duke expects to file a notice of intent for the Catawba/Wateree project, which is five years before the expiration of the license. This project includes the following developments: Bridgewater, Rhodhiss, Oxford, Lookout Shoals, Cowans Ford, Mountain Island, Wylie, Fishing Creek, Great Falls, Dearborn, Rocky Creek, Cedar Creek and Wateree. No capacity upgrades are proposed at this time. Carolina. NC Power owns 100 MW of conventional hydroelectric generation in North (b) Qualifying Facilities Using Renewable Fuel Sources As stated in the introduction to this chapter, North Carolina has separately encouraged the development of small hydroelectric generating facilities. In 1979, the General Assembly enacted a new statute, G.S , and amended the definitions section of Chapter 62 to include a definition of "small power producer." (G.S. 62-3(27a). Pursuant to those two provisions, a hydroelectric facility of no more than 80 MW in size that is not owned by a person primarily engaged in the production or sale of electricity from other types of facilities, is entitled to have the Commission require a public utility 3-10

11 subject to its jurisdiction to purchase its power at avoided cost rates determined in accordance with G.S (b). Under that subsection, the Commission is required to determine such purchase rates every two years, and long-term contracts are specifically encouraged to enhance development. In its initial proceedings pursuant to PURPA and G.S , the Commission decided to hold biennial proceedings to determine avoided cost rates, appropriate contract terms and conditions, and other related matters. The Commission certificated a significant number of very small scale hydroelectric projects and most of their owners entered into 15-year levelized purchase power contracts with CP&L and Duke. As a result of declining avoided cost rates over the years, very few applications for certificates for hydroelectric projects have been filed in recent years. Many of the initial ones are at or near the end of their initial 15-year contracts and are faced with signing new contracts at rates much lower than those initially offered. A few other QFs, mainly fueled by landfill gas, waste, and wood waste have obtained certificates and signed purchase power contracts with the utilities. These are discussed in some detail later in this section. (c) Study Commission and "Green" Power Encouragement In January 2001, the Study Commission on the Future of Electric Service in North Carolina (Study Commission) requested the Commission to investigate and make recommendations on the possible creation of voluntary green, or renewable, energy, and public benefit fund check-off programs. The Commission initiated an investigation by opening Docket No. E-100, Sub 90, and requesting response to eight specific questions. Based on that investigation, the Commission concluded, in a March 2002 report to the Study Commission, that there would be considerable benefit in exploring implementation of a statewide voluntary green power program for North Carolina. The Commission concluded that a successful green power program would have a positive impact on the environment in North Carolina by increasing the amount of electricity generated by domestic, renewable energy resources. The inclusion of hog and poultry 3-11

12 waste-to-energy projects was found to have additional economic and environmental benefits. CP&L and Duke both committed to filing green pricing tariffs, which were perceived as likely to be more effective than a voluntary check-off program. To reach consensus, the Advanced Energy Corporation (AEC) facilitated the organization of an advisory committee. Work is continuing on this effort at this time. CP&L, Duke and NC Power filed tariffs on May 31, 2002, as did several electric membership cooperatives. The Commission currently is having public hearings on this matter in several locations around the State. (d) Cardinal Energy Services Report Cardinal Energy Services, Inc. (Cardinal), published a report in late November 2001 to document the inventory of existing renewable generating facilities operating in North Carolina and to establish a reasonable estimate of the development of renewable generation in the near future to aid in developing the above-described green power program. According to the EIA (Appendix C of Cardinal s report), generation fueled by renewable resources existing in North Carolina in 1998 can be categorized as follows: 1,552 MW of utility-owned hydroelectric generation; 75 MW of industrial-owned hydroelectric generation; 318 MW of industrial-owned biomass generation (mainly paper and lumber mills); 32 MW of nonutility, independent hydroelectric generation; and 73 MW of nonutility, independent biomass generation, for a total of 1,659 MW of hydroelectric and 391 MW of biomass generation. The sum of these two types of renewable generation equals 2,050 MW, which was 8.98 percent of total generating capacity (including self-generation) in North Carolina in Cardinal s report shows independent renewable generation in 2000 to be as follows: two biomass units with a capacity of 52.5 MW and producing 394 million kwh; 36 small scale hydroelectric plants with capacity of 37.4 MW and producing 46.8 million 3-12

13 kwh; 12 three landfill gas projects with capacity of 11.7 MW and producing 62.1 million kwh; 18 solar photovoltaics units with.06 MW of capacity and producing 78,000 kwh; and two agricultural waste-to-energy projects with 0.2 MW of capacity and producing 259,000 kwh. (Industrial-owned cogeneration plants not directly connected to the utility grid are not included in these totals.) Assuming that the new green power program was put into place during 2002, Cardinal estimates that under the Baseline Scenario, which assumes three percent customer participation by 2006 and continuing on into the future, the existing 102 MW of capacity and 503,000 MWh of energy can be increased to 218 MW of capacity and 1.1 million MWh by 2006 and to 365 MW and 1.7 million MWh by Under the Aggressive Development scenario, which assumes a favorable technological and financial environment and nine percent participation by customers through 2006, existing capacity and energy can be increased to 456 MW of capacity and 2.2 million MWh by 2006 and to 811 MW and 3.7 million MWh by In addition to the three landfill gas projects identified in Cardinal s report that sell electricity, there are a number of landfill to energy projects in operation in North Carolina that do not involve the production of electricity. With one exception, the one in Yancey County, these involve the use of landfill gas to make steam, predominantly for process use. A greenhouse uses the landfill gas from the Yancey County project. These projects are as follows: 12 Because small scale hydro plants for the most part must be operated as run-of-the-river (no storage), they seldom generate the amount of their nameplate capacity. Actual output is probably comparable to 25 to 40 percent of the total 37 MW. Cardinal s report, p Cardinal Report, p

14 NAME COUNTY DEVELOPER Buncombe County Buncombe Enerdyne City of Raleigh Wake Natural Power Cumberland County Cumberland Enerdyne City of Greensboro Guilford Natural Power Henderson County Henderson Enerdyne North Wake Wake Enerdyne Pitt County Pitt Enerdyne Yancey/Mitchell Counties Yancey Blue Ridge RC&D Future projects are being considered in Rockingham, Wilkes, New Hanover, Onslow, Sampson, Johnston, Orange, and Harnett Counties. B. COAL 1. UNITED STATES While coal is expected to remain the predominant fuel used for generation over the next 20 years, its share of generation is expected to decline. The EIA expects coal s share of generation to decline from 52 percent to 46 percent nationally, as a more competitive industry invests in the less capital-intensive and more efficient natural gas generation technologies. 14 The average minemouth price of coal is projected by the EIA to decline from $16.45 per ton in 2000 to $12.79 per ton in The projected price decline results from increasing productivity, a shift to western production and competitive pressures on labor costs. Productivity improvements have averaged 6.6 percent per year since The EIA s Overview, Annual Energy Outlook 2002, p

15 The EIA expects the sulfur emissions cap from the Clear Air Act Amendments of 1990 to encourage progressively greater reliance on lower sulfur coal from mines in Wyoming, Montana, Colorado, and Utah, which tend to be lower cost mines, thus pushing prices down overall. 15 In the East, the EIA expects generators to shift to lower sulfur Appalachian bituminous coals that contain more energy (Btu) per ton than the higher sulfur coal. Total coal consumption is expected to increase from 1,081 million tons to 1,365 million tons between 2000 and 2020, an average increase of 1.2 percent per year. Electricity generation constitutes about 90 percent of the domestic demand for coal. While the EIA expects coal s share of generation to decline from 52 percent to 46 percent as a more competitive industry invests in natural gas generation technologies, the utilization of existing coal-fired generating plants is expected to continue to increase, as demand for electricity continues to increase. The average capacity factor of coalfired plants was 59 percent in This increased to approximately 70 percent by 2001, and is expected to increase to 80 to 85 percent by Coal production is projected to increase at an annual rate of 1.3 percent, from 1,084 million tons in 2000 to 1,397 million tons in The United States share of coal exports is expected to decline, as European demand for imports declines as a result of environmental concerns. 16 The United States share of total world coal trade is projected to decline from ten percent in 2000 to eight percent in The use of western coal can result in up to 85 percent lower sulfur dioxide emissions than the use of many types of higher sulfur eastern coal. As coal demand grows, new plants will be required to use the best available technology: scrubbers or advanced coal technologies that can reduce sulfur emissions by 90 percent or more. High and medium sulfur coal production is projected to remain essentially flat, while low The EIA s Annual Energy Outlook 2002, p. 92. Id., at p. 7. The EIA s Annual Energy Outlook 2002, p

16 sulfur coal production is expected to increase 2.5 percent per year to By 2020, it is projected that 23 GW (23,000 MW) will have been retrofitted with scrubbers to meet the requirements of the Clean Air Act Amendments of The shift to western coal is expected to increase the tonnage per kilowatt-hour of generation in the Midwest and Southeast. 20 Between 2005 and 2020, rising natural gas costs, increasing demand for electricity, and retirements of existing nuclear and fossilfueled steam capacity are projected to result in increasing demand for coal-fired baseload capacity. While the United States has huge coal reserves, domestic production has declined in the last few years mainly because of low prices during the 1990 s. Colder than normal weather in November and December 2000 and record high natural gas prices contributed to high coal consumption and coal unit dispatch in The competition between coal and other fuels, and among coal fields, is influenced by coal transportation costs, but they are balanced to some extent by improvements in transportation fuel efficiency. Because of technological improvements that allow longer trains and more coal in each car, productivity has increased and is expected to continue to increase. Overall, average coal transportation rates are expected to decline 1.3 percent per year between 1999 and Any coal transportation problems associated with the increased shift to low sulfur coal, due to the need to expand train-loading capabilities, are expected to be temporary. For plants with access to only one railroad and no other mode of transportation, costs are expected to be stable Id., at p. 92. Id., at p. 75 Id., at p

17 2. NORTH CAROLINA (a) Utility-Owned Coal-Fired Generation CP&L According to CP&L s September 2001 Resource Plan, CP&L has total coal-fired capacity of 5,285 MW. 21 Of this, the North Carolina Eastern Municipal Power Agency (NCEMPA) owns 211 MW, for a net of 5,074 MW. All but 174 MW of this capacity is located in North Carolina. Specific information by plant is as follows: Plant County Size Roxboro Person Four units - 2,462 MW (CP&L owns 2,371 MW) 22 Mayo Person One unit MW (CP&L owns MW) 23 Sutton New Hanover Three units MW Lee Wayne Three units 407 MW Asheville Buncombe Two units MW Cape Fear Chatham Two units MW Weatherspoon Robeson Three units MW Robinson South Carolina One unit MW For the 12 months ending December 21, 2001, 45 percent of CP&L s total capacity (net of NCEMPA) was coal-fired. (Net of NCEMPA s ownership interests, CP&L has a total of 11,400 MW of capacity, 5,074 MW of which is coal-fired.) With respect to energy production, 27,823,518 MWh out of 50,281,876 MWh were produced at CP&L s coal-fired plants, making 55 percent of CP&L s total MWh coal-fired. (This also is net of NCEMPA s ownership interests.) Capacities are summer ratings. NCEMPA owns 90.6 MW of the Roxboro plant. NCEMPA owns MW of the Mayo plant. 3-17

18 Duke According to Duke s September 2001 Resource Plan, Duke has total coal-fired capacity of 7,699 MW. 24 All but 370 MW of this capacity is located in North Carolina. Specific information by plant is as follows: Plant County Size Belews Creek Stokes Two units - 2,240 MW Marshal Catawba Four units - 2,090 MW Allen Gaston Five units MW Cliffside Cleveland Five units MW Buck Rowan Four units MW Dan River Rockingham Three units MW Riverbend Gaston Four units MW Lee South Carolina Three units MW For the 12 months ending December 31, 2001, 44 percent of Duke s total capacity was coal-fired. (Net of the ownership interests of the other owners of the Catawba nuclear plant, Duke has a total of 17,373 MW of capacity, 7,699 MW of which is coal-fired.) With respect to energy production, 41,795,486 MWh out of 82,854,277 MWh were produced at Duke s coal-fired plants, making 50 percent of Duke s total MWh coal-fired. (Duke's MWh total also is net of the other owners of Catawba.) (b) Nonutility-Owned Coal-Fired Generation In the mid-1980's, Cogentrix, Inc., built five coal-fired qualifying facilities to sell electricity to CP&L and steam to each of the five industrial hosts. The contracts for three of the facilities have expired. Two of those, the ones located in Lumberton and Elizabethtown, both of which are 35 MW, were sold to Enron and then to AIG Highstar, which intends to run them as EWGs. The third facility with an expired contract is 24 Capacities are summer ratings. 3-18

19 located in Kenansville. It is a 33 MW facility, and Cogentrix has recently indicated, by filing dated June 28, 2002, that it proposes to sell it to Green Power Energy Holdings, LLC. Green Power intends to convert it into a wood waste-fired generating facility. The two QFs with unexpired contracts are located in Roxboro and Southport. Both of them have contracts that expire December 15, The Roxboro facility is 107 MW, and the Southport facility is 56 MW. In Duke s territory, RJR in Forsyth County at its Tobaccoville manufacturing facility built an 80 MW QF during the 1980 s. It has a contract to sell 52 MW to Duke that expires December 31, It uses the rest of the output as self-generation. Duke also buys ten KW (0.1 MW) from Kannapolis Energy Partners, the contract for which expires February In NC Power s territory, there are three coal-fired QFs: Cogentrix Rocky Mount, which is MW (summer rating), is located in Rocky Mount, and commenced operations in October 1990; Roanoke Valley I (ROVA I), which is 165 MW (summer), is located near Roanoke Rapids, and commenced operations in May 1994; and Roanoke Valley II (ROVA II), which is 44 MW (summer), also is located near Roanoke Rapids, and commenced operations in June (c) New Developments In June 2002, the General Assembly passed and Governor Easley signed a bill that requires that pollution be lowered from 14 coal-fired power plants located in North Carolina and owned by CP&L and Duke. This new law requires that sulfur dioxide emissions be lowered to 250,000 tons by January 1, 2009, and to 130,000 tons by January 1, 2013, and that nitrogen oxide emissions be lowered to 56,000 tons by January 1, While it is not definite at this time, at least part of the reductions would occur as a result of the installation of scrubbers. The installation of scrubbers would cause the North Carolina utilities to not purchase as much lower sulfur coal, which may reduce the overall cost of coal and transportation costs. The effects of this plan on the 3-19

20 availability and cost of coal will need to be considered after details of the utilities compliance plans become better known. C. NUCLEAR 1. UNITED STATES The United States currently has 104 operable nuclear units, which provided 20 percent of total electric generation in The national average capacity factor for these plants is 88 percent. Performance is expected to continue to improve to an expected average capacity factor of 90 percent by The EIA s Annual Electric Outlook 2002 projects that ten percent of current nuclear capacity will be taken out of service by 2020, primarily because of the high costs of maintaining the performance of older nuclear units, as compared to the costs of constructing the least cost alternatives. No new nuclear units are expected to become operable between 2000 and 2020 because natural gas and coal-fired units are projected to be more economical. 25 The price of uranium is not expected to increase in real terms over the next 20 years. As of October 2001, the Nuclear Regulatory Commission (NRC) had approved license renewals for six nuclear units and 14 other applications had been filed. Twentyfour other applicants have announced intentions to pursue license renewals over the next five years. In the SERC subregion, 17% of installed capacity is nuclear, with over 31% of energy requirements provided by nuclear plants. Almost 24% of the operational licenses for nuclear units in the SERC region will expire by However, most are expected 25 The EIA s Annual Energy Outlook, p

21 to be renewed. A list of nuclear units in the Southeast, by NERC subregion, utility, plant name, type, capacity, commercial operation date, and original retirement date, is attached at the end of this chapter as Attachment III-A. Investments in existing plants are expected to make nuclear power a growing source of electricity through As a result of recent improvements in the performance of nuclear power plants, nuclear generation is projected to remain at current levels until 2006, then decline as older units are retired NORTH CAROLINA (a) Utility-Owned Nuclear Generation CP&L According to CP&L s September 2001 Resource Plan, CP&L has total nuclear capacity of 3,183 MW. Of this, NCEMPA owns 429 MW, for a net CP&L amount of 2,745 MW. All but 683 MW of this capacity is located in North Carolina. Specific information by plant is as follows: Plant County Size Brunswick Brunswick Two units - 1,631 MW (CP&L owns 1,350 MW) 27 Harris Wake One unit MW (CP&L owns 721 MW) 28 Robinson South Carolina One unit MW For the 12 months ending December 21, 2001, 26 percent of CP&L s total capacity was nuclear, including NCEMPA s jointly-owned plants. (Net of NCEMPA s ownership interests, CP&L has a total of 11,400 MW of capacity, 2,745 of which is CP&L-owned nuclear. which is 24 percent of CP&L s capacity.) With respect to energy Id., at p. 75. NCEMPA owns MW of each unit for a total of MW. NCEMPA owns MW. 3-21

22 production, 21,321,474 MWh out of 50,281,876 MWh were produced at CP&L s nuclear plants, making roughly 40 percent of CP&L s total MWh nuclear. (CP&L s total MWh are net of NCEMPA s ownership interests.) CP&L s September 2001 Resource Plan shows the following uprating in capacity for CP&L s nuclear units: Unit and Plant Name Capacity Uprate Expected In-Service Date Brunswick No MW 10/02 Robinson 18 MW 10/02 Harris 40 MW 1/02 Brunswick No MW 4/03 Brunswick No MW 4/04 Brunswick No MW 4/05 In June, the NRC approved CP&L s plan to increase generating capacity at its Brunswick plant. According to the NRC s statement, the approved increases would boost the output of the two Brunswick units by 233 MW (117 MW at No. 1 and 116 MW at No. 2), which is lower than the 246 MW shown in CP&L's annual resource plan. The NRC s statement also indicated that all of the work would be completed by With respect to relicensing, CP&L s September 2001 plan indicates that its current plans are to request an operating license extension for its oldest nuclear unit, Robinson, from the NRC in The current license for the Robinson nuclear unit expires on July 31, Duke According to Duke s September 2001 Resource Plan, Duke has total nuclear capacity of 6,996 MW. Of this, 1,976 MW of it is owned by the North Carolina Electric Membership Corporation (NCEMC), the Saluda River Electric Cooperative, Inc., North Carolina Municipal Power Agency No. 1 (NCMPA No. 1), and Piedmont Municipal Power Agency, leaving Duke with net nuclear capacity of 5,020 MW. Approximately

23 percent of this nuclear capacity is located in North Carolina. Specific information by plant is as follows: Plant County Size McGuire Mecklenburg Two units - 2,200 MW Catawba South Carolina Two units 2,258 MW (Duke owns 282 MW) 29 Oconee South Carolina Three units - 2,538 MW For the 12 months ending December 21, 2001, the percentage of Duke s total capacity that was nuclear, net of the portions of Catawba owned by others, was roughly 30 percent. (Net of the ownership interests of the other owners of Catawba, Duke has a total of 17,373 MW of capacity, 5,020 MW of which is nuclear.) With respect to energy production, 24,753,799 MWh out of 82,854,277 MWh were produced at Duke s nuclear plants, making 29.9 percent of Duke s total MWh nuclear. (This is net of the ownership interests of the other owners of Catawba.) With respect to relicensing, Duke s September 2001 plan indicates that on May 23, 2000, the NRC approved the renewal of the licenses for all three units of Oconee. With the renewal, the original 40-year licenses have been extended 20 years. Units 1 and 2 originally expired in 2013; they now expire in Unit 3 would have expired in 2014 and now expires in Duke applied in June 2001 for the renewal of the licenses for both McGuire units, which currently expire in 2021 and 2023, and both Catawba units, which currently expire in 2024 and If renewal is granted, each of these licenses would be extended for an additional 20 years. 29 Each unit is 1,129 MW for a total of 2,258 MW. Duke owns 25 percent of one unit or 282 MW. NCEMC, NCMPA No. 1, Piedmont Municipal Power Agency (SC) and Saluda River Electric Cooperative own the remaining 1,976 MW. 3-23

24 D. CONCLUSIONS Renewable capacity is expected to increase on both a national basis and in North Carolina. The issues associated with using renewable fuels for the generation of electricity typically are the relative high costs of the technology more than the availability of the fuels, although some are very site specific and/or limited (e.g., water, wind). Coal is expected to remain the predominant fuel used to generate electricity, but its share is expected to shrink significantly as natural gas-fired plants are brought on line. There are no significant supply issues, and the overall cost is expected to decline. The biggest issues relate to pollution and emissions standards, including the extent to which scrubbers are installed and the effect of that on the price of low versus high sulfur coal. North Carolina s installation of scrubbers in order to comply with the recently passed legislation requiring the reduction in emissions from coal-fired plants should have a neutral to positive effect on the price CP&L and Duke pay for coal. Finally, nuclear generation is expected to stay relatively constant or increase slightly due to upgrades, as CP&L and Duke move through the re-licensing process at the NRC for their existing nuclear units. 3-24

25 IV. WATER SUPPLY Historically, North Carolina has had a generous supply of water. Consequently, there are no statewide water use permitting requirements. However, according to the January 2001 State Water Supply Plan, problems are beginning to be experienced in some areas. Numerous regulations and governmental programs exist that must be considered. The first section of this chapter discusses those regulations and programs. Subsequent sections discuss statewide water use for all purposes; the use of water for gas-fired generation, including the merchant plants for which certificate applications have been filed; and how water use issues are handled in the Commission's certification process. The final section contains the Public Staff's recommendations. A. REGULATIONS AFFECTING WATER SUPPLY PLANNING 1 1. WATER USE ACT OF 1967 State authority over water use increased substantially when the General Assembly passed the Water Use Act of 1967, which is codified as G.S This act was passed in response to concerns about potential ground water problems in the vicinity of a proposed phosphate mine in Beaufort County. Under this statute, if the Environmental Management Commission (EMC) finds that the use of water resources in an area requires coordination and regulation to protect the interests and rights of residents and property owners or to protect the water resources, the EMC can declare the area to be a Capacity Use Area (CUA). In a CUA, water withdrawals above 10,000 gallons per day require a permit from the EMC, and limitations of the quantity and timing of water withdrawals can be imposed. 1 State Water Supply Plan - January It can be accessed from the following web site address: 4-1

26 As of December 2000, only one CUA has been designated, which is the area around the phosphate mine near Aurora in Beaufort County. It includes all or part of eight counties: Carteret, Craven, Pamlico, Beaufort, Martin, Washington, Tyrrell, and Hyde. An additional CUA has been proposed, however. In December 2000, the EMC approved a set of rules to declare a 15-county area in the Central Coastal Plain a CUA due the to over-pumping of ground water. The rules are subject to further review, but could become effective in the near future. The counties proposed to be included, in whole or in part, are the following: Edgecombe, Martin, Washington, Beaufort, Pitt, Wilson, Wayne, Green Lenoir, Craven, Pamlico, Carteret, Onslow, Jones, and Duplin Counties. Other areas of eastern North Carolina about which ground water concerns have been expressed include the following: (1) the Lumber River Council of Governments has expressed concern about ground water levels in Robeson, Bladen and Columbus Counties; (2) New Hanover, Brunswick and Onslow Counties are experiencing salt water intrusion in water supply aquifers; (3) the six-county area in the North Albemarle region (Gates, Chowan, Perquimans, Pasquotank, Camden and Currituck) are experiencing saline water threatening surface and ground water supplies and low yielding wells; and (4) Currituck Outer Banks, which needs to augment water supply. 2. LOCAL AND STATE WATER SUPPLY PLANNING The need to look at how communities meet their water supply needs resurfaced in the mid-1980 s due to a multi-year drought. In 1989, the General Assembly passed legislation to require the development of a State Water Supply Plan. This legislation added sections (l) and (m) to G.S The Division of Water Resources (DWR) within the North Carolina Department of Environment and Natural Resources (DENR) is responsible for the implementation of these provisions of the statute. 4-2

27 Section (l) requires units of local government that provide or plan to provide public water service to develop a Local Water Supply Plan (LWSP) and requires that present and future water use and water supplies be projected. An LWSP is basically an assessment of a system s water supply needs for a 20 to 25-year period and the ability of that system to meet those needs. For systems with average daily demands that exceed 80 percent of their available supply during the planning period, a specific plan is required for meeting those needs. The plans must be revised at least every five years to reflect changes in relevant data, unless a more frequent revision is requested by DWR. Section (m) requires that a State Water Supply Plan be developed based on the information included in the LWSPs and in other appropriate information sources. As of September 1996, DWR had received draft LWSPs from 500 water systems for review. As of September 1, 1996, 416 LWSPs were on file with DWR that met the minimum requirements of the law and had been adopted by the local governing board as required by the law. A second round of plans began to be prepared using 1997 water supply and demand information. As of December 2000, only 16 of the 553 water systems expected to submit plans had not submitted a draft 1997 LWSP. 3. INTERBASIN TRANSFER OF SURFACE WATER Water is not distributed evenly across the State, which can necessitate the transfer of water from one area to another. In 1993, the Regulation of Surface Water Transfers Act, which is codified as G.S , was enacted to regulate large surface water transfers between river basins by requiring a certificate from the EMC. There are 38 defined river basins in North Carolina, which are grouped into 18 major river basins. These are shown on the map that follows this section. Transfers between any of the 38 river basins may require a certificate, depending upon the transfer amount. A transfer certificate is required for a new transfer of two million gallons per day (MGD) or more and for an increase in an existing transfer by 25 percent or more, if 4-3

28 the total transfer including the increase is two MGD or more. The responsibility for obtaining a transfer certificate lies with the owner of the pipe that crosses the basin boundary. A certificate will be granted if the applicant establishes and the EMC concludes that the benefits of the proposed transfer outweigh the detriments of the transfer and the detriments have been or will be mitigated to a reasonable degree. Transfers requiring certification also are subject to the State Environmental Policy Act (SEPA), which can require either an Environmental Assessment or an Environmental Impact Statement, depending on the issues involved. The process, therefore, can take two to three years to complete. 4-4

29

30 4. REGISTRATION OF WITHDRAWALS AND TRANSFERS In 1991, the General Assembly required any person who withdraws or transfer one million (1,000,000) gallons per day or more of surface water to register those withdrawals with the DWR. (G.S H) The law was changed in 1993 to require also the registration of ground water withdrawals and to exempt local government water systems with local water supply plans from the registration requirement. In 1998, the registration threshold was lowered for all water uses except agriculture from one MGD to 100,000 gallons per day. Registrations must be updated every five years. Registered water withdrawals in 1999 for agricultural use were 198 MGD from surface water (160 MGD of which was for irrigation) and 38 MGD from ground water, for a total of 236 MGD. Non-Agricultural Uses (i.e., Public Water Supply, Industrial, and Mining, but not Power Generation) were 1,019 MGD from surface water and 117 MGD from ground water, for a total of 1,136 MGD. For power generation, registered withdrawals from surface water were 16,362 MGD for hydroelectric power and 8,747 MGD for thermal power and registered withdrawals from ground water were zero, for a total of 25,109 MGD BASINWIDE WATER QUALITY PLANNING In 1991, the Division of Water Quality (DWQ) instituted a basinwide approach to water quality management. Water quality management plans have been prepared for each of the major river basins in the State and will be updated every five years. This approach features basinwide permitting of wastewater discharges and the integration of existing point and non-point source programs within each basin. 2 State Water Supply Plan - January 2001, Table 8-4, p

31 6. OTHER REQUIREMENTS Policies have been adopted to ensure adequate instream flows below reservoirs and river intakes and minimum statewide water supply measures have been established by the passage in 1989 of the Water Supply Watershed Protection Act, which is codified as G.S and G.S These are discussed in some detail in the January 2001 State Water Supply Plan on pages 6-4 and 6-5. Other current water supply issues include the allocation of water supply storage in Jordan Lake; FERC relicensing of all of the major hydroelectric plants in the State between 2001 and 2008; drought monitoring and response (mainly in the western part of the State); and population growth in the Piedmont Urban Crescent in the headwaters of the Cape Fear, Neuse, and other river basins, in some mountain river basins, and in the Eno River Voluntary Capacity Use Area. In addition to the foregoing, plans for expansions of existing water systems and plans for new ones must be submitted to the Public Water Supply Section of the Division of Environmental Health for approval. B. STATEWIDE WATER USE The most recent estimate of total water use in North Carolina was compiled by the United States Geological Survey in the mid-1990 s. This survey estimated that total water use in North Carolina was 9,286 MGD, of which 8,751 MGD was surface water and 535 MGD was ground water. Eighty percent of the total water used was for thermoelectric power generation, virtually all of which was from surface water. Public water systems withdrew 633 MGD of surface water and 136 MGD of ground water. The table on the following page shows water use by type (e.g., domestic, commercial) and by source (i.e., surface or ground). 4-7

32 STATEWIDE WATER USE IN (Million Gallons per Day) Self-Supplied Self-Supplied Public Total Type of Use Surface Water Ground Water Supply Use Domestic Commercial Industrial Mining Irrigation Livestock Thermoelectric 7, ,417 Public Water Losses Totals 8, ,286 Information provided in the January 2001 State Water Supply Plan indicates that 8,451 MGD of the 9,286 MGD used in 1995 was considered returned flow. Consumptive use was only 730 MGD. According to this report, while thermoelectric use dominates water uses in the State, 7,343 MGD of the 7,417 MGD it used in 1995 was returned and available for uses down river. 4 A breakdown of the total use, returned flow, and consumptive use by type of use follows: Total Returned Consumptive Type of Use Use Flow Use Domestic Commercial Industrial Mining Irrigation Livestock Thermoelectric 7,417 7, Public Water Losses Totals 9,286 8, State Water Supply Plan - January 2001, Table 8-1, p Source: Figure 2, Estimated Water Use, by County, in North Carolina, USGS Open File-Report Id. 4-8

33 Systems with Local Water Supply Plans experienced a 26% increase in water use from 1992 to 1997, while experiencing a population increase of 20 percent. By 2020, water use is expected to increase by 63 percent above 1997 levels, based on population growth from approximately five million people served to approximately eight million served, which is about a 60 percent increase. 5 C. GAS-FIRED GENERATION AND WATER SUPPLY As noted above, while thermoelectric use has dominated surface water uses in the State in the past, virtually all of the water used for this purpose was returned and was available for uses down river. This is not the expected pattern of use for combined cycle natural gas-fired plants. According to information received from several sources, a combined cycle plant of 1,100 MW would use 8.0 MGD at peak operations, 5.5 MGD of which would evaporate in the process, with 2.5 MGD being pretreated and returned to the supplier. 6 Other estimates indicate that up to 85 percent of the water supply would not be returned. It appears that unless an interbasin transfer is involved or a person other than a local government plans to withdraw more than 100,000 gallons per day (thereby requiring registration with the DWR), 7 the current set of water supply regulations do not require any permits or other regulatory action. To the extent a pattern has emerged among merchant plants with respect to water supply, the pattern is an intention to rely upon local public water systems. The 1997 projections discussed above do not include proposed water use by these merchants. Because these plans are updated only every five years, it would be difficult for this process to adequately plan for the addition of such large users. This is especially true given the relatively short construction time for a natural gas-fired plant and the even shorter time period required for the conversion of a 5 Id., at p E.g., Dominion s Person County project, based on information provided to the Public Staff at an informational meeting in A proposal to withdraw ground water in excess of 10,000 gallons per day in a CUA also would trigger a permit requirement. 4-9

34 combustion turbine plant into a combined cycle plant, which greatly increases water use. Very generally speaking, the main stems of the numerous major rivers across the State would appear to be feasible water sources for power generation projects. However, because of other factors, such as pre-existing water withdrawals, wastewater flows, and instream flow considerations, many sites along these main stems might not be appropriate locations. Whether there is a sufficient supply of water for a generating plant, therefore, has to be a very site specific determination. A natural gas-fired combustion turbine peaker of 160 MW uses approximately 2,400 gallons of water per hour, which would be approximately 30,000 gallons per day (assuming 12 hours of operation a day). Utilities historically have operated their CTs at capacity factors of between two and five percent, which would be approximately 175 to 438 hours per year. New CTs, however, may be run more often. At a ten percent capacity factor, a CT would run 876 hours per year, which, for a 160 MW CT, would mean two million gallons per year would be used. It is too soon to know how merchant CTs will be operated. So far the merchant peaking plants that have been certificated all have limitations in their air permits of from 2,000 to 4,400 hours per year, which produces a range of capacity factors from approximately 23 percent to just over 50 percent. At a 50 percent capacity factor, a 160 MW CT would use over ten million gallons of water a year. With respect to the water use of combined cycle plants, the information that has been provided to the Public Staff varies somewhat by plant. The estimated use ranges from 5,400 gallons to 7,200 gallons per MW per day. The estimates as to the percentage of water consumed (i.e., not returned) also varies, from approximately 75 percent to 85 percent of the total amount of water supply. For example, CP&L indicated in its prefiling for additional units at its Rowan County and Richmond County sites that a 500 MW combined cycle plant would 4-10

35 consume approximately 3.5 MGD. The applications and/or testimony filed by Fayetteville Generation and Carolina Generation indicate a higher amount of water consumed on a per MW basis. Differing assumptions with respect to the number of hours run and in the configuration of each plant are likely the cause of these differences. Most of the existing CTs belong to the utilities, and they were constructed on the sites of their coal-fired plants and use the same water source. For example, CP&L's Wayne County CTs use the same water source as its Lee coal-fired plant. The same is true for CP&L's plants in Buncombe County. CP&L's Richmond County site was a new one, however. CP&L s application indicated that it intends to obtain its water supply from the Richmond County water system. With respect to existing nonutility plants, Dynegy, whose affiliate Rockingham Power, LLC, built an 800 MW CT facility in Rockingham County, purchases the water it needs through a new water line to the City of Reidsville water supply. With respect to proposed nonutility combined cycle plants, GenPower s application indicates that it will need three to four MGD, which it intends to obtain by using effluent water provided by Hertford County via a new county wastewater collection facility proposed to be located near the plant site. A storage pond sized for seven days will be constructed as back up and to control run off. A system of wells also is being evaluated to serve as a back-up system. Mirant s proposed combined cycle plant intends to connect directly to the City of Gastonia s utility system. Mirant will construct a new water transport line between Rankin Lake and the site. According to newspaper accounts, supply is not an issue because of the number of textile plant closings in the area. Fayetteville Generation s proposed combined cycle plant (Cumberland County) intends to obtain its water supply from the Cross Creek Water Reclamation Facility 4-11

36 (CCWR). According to the application, the use of reclaimed water will minimize freshwater use and the impact of the project on the Cape Fear River watershed. The combined cycle plant proposed by Carolina Generation in Richmond County is considering using a mixture of raw water from the Pee Dee River (via the Richmond County water system), raw water from Marks Creek (via the City of Rockingham water system) and the wastewater effluent from the Rockingham Waste Water Treatment Plant. Dominion Person s proposed combined cycle plant, which would be located in Person County, intends to obtain water supply from the City of Roxboro, which Roxboro intends to obtain through an interbasin transfer. Roxboro recently submitted the required NEPA/SEPA Environmental Scoping Document to DENR for the proposed interbasin transfer from the Roanoke River Basin to the Neuse and Tar River Basins to enable it to provide seven MGD of raw cooling water to Dominion s proposed 1,100 MW generating plant. Notice of Public Comment was recently published and a number of comments were filed with the North Carolina State Clearinghouse. Various divisions of DENR raised questions and concerns, and the North Carolina Wildlife Resources Commission filed ten pages of comments with numerous specific recommendations and proposed conditions. Caswell County submitted the most comprehensive comments. These can be summarized as follows: (1) The need for the project is clearly based on the construction of the Dominion Energy plant, and the plant is dependent upon the project. The plant, therefore, should be considered part of the project and the environmental impacts of the plant should be included in the scoping process. (2) The project will involve a water intake in Caswell County, approximately 22.4 miles of pipeline to transport the water to the proposed power plant, and a pipeline crossing the Hyco Reservoir, among other things. The environmental impacts of the project, as well as the cost, are greatly 4-12

37 increased by locating the intake and the power plant so far apart. Consequently, thorough analysis and discussion should be done of alternative plant and intake locations and the difference between their environmental impacts. Clearly the impacts would be reduced if the plant were located nearer the intake. (3) The need for the project for water supply should be carefully analyzed. Given Person County s relatively low population growth, an interbasin transfer of this size is not adequately supported. Clearly the intake is being built for the Dominion power plant, which is seen as an opportunity to construct a greatly oversized intake. (4) Location of the water supply intake at Milton in Caswell County will necessitate designating and reclassifying waters above the intake to a water supply classification. Consequently, Caswell County will be required to establish a water supply watershed and adopt and administer land use and development regulations according to minimum state guidelines. Caswell County will incur direct costs associated with these regulatory tasks and property values in the water supply watershed may be detrimentally affected. These detriments would be incurred by Caswell County without it enjoying any of the benefits of the project. (5) While the proposed withdrawal is only 12 percent of the estimated 7 Q10 value (which is a measurement of the amount of flow) for the Dan River, an extraordinarily high percentage of the water to be withdrawn by Dominion will be consumed through evaporation (approximately 75%). The impacts of this extraordinarily high consumption rate on the flow of the River should be considered. In addition to the foregoing, Caswell County s comments note that, prior to the acquisition of property by a county or city in another county, North Carolina law requires approval by the County Commissioners in the other county. According to these comments, neither Roxboro nor Person County has requested such approval and Caswell County questions the prudence of initiating expensive environmental documentation and regulatory processes before such approval has even been discussed. The comments conclude that approval by the Caswell County Board of Commissioners should not be assumed at this time, particularly in view of the fact that Caswell County will receive only detriments from the project without any of the benefits, which is a prominent factor to be considered in deciding whether an interbasin transfer can be approved. 4-13

38 D. WATER SUPPLY ISSUES AND THE COMMISSION S CERTIFICATION PROCESS In 1978, the North Carolina Court of Appeals, in a case involving water issues and Duke Power s proposed Perkins nuclear station, held that environmental concerns generally had been left to regulatory agencies other than the Utilities Commission, except as they affect the cost and efficiency of the proposed generating facility. The holding rejected the appeal of High Rock Lake Associates, Inc., a nonprofit corporation organized to promote the recreational benefits and property values around High Rock Lake, and others, who alleged that the Commission s grant of a certificate to Duke Power for its proposed plant on High Rock Lake was erroneous. The alleged error was an inadequate consideration of flaws in the design and placement of the generating plant because it would consume too much water and pollute the Yadkin River. The Court further stated, that, even though these issues were not at the heart of the regulatory process before the Commission, the Commission had adequately considered them by conditioning the certificate on approval of the plant s construction by other agencies better equipped to deal with environmental issues. State of North Carolina ex rel. Utilities Commission v. High Rock Lake Association, Inc., 37 N.C.App. 138, 235 S.E.2d 787, cert. denied, 295 N.C. 646, 248 S.E.2d 257 (1978). Thus, generally speaking, the Commission does not adjudicate environmental issues when considering applications for certificates to build generating facilities. Certificate applications are sent to the State Clearinghouse to be distributed to all interested state agencies, but except in a few fairly isolated instances, the Commission has not ruled on environmental issues. These occurred because one or more state agencies without permitting authority requested that the Commission take action in 4-14

39 several applications for hydroelectric QFs that did not need to go through the FERC s licensing process. 8 E. CONCLUSIONS Because permits for water use apparently are unlikely to be required for merchant plants under current North Carolina law and regulations, the Commission should consider consulting with the relevant divisions and sections of DENR about their needs for information about the proposed sources and quantities of water supply for proposed merchant plants. The Commission should then consider requiring appropriate information to be filed in merchant applications to provide a timely source of information on which an assessment could be made of the potential effects of merchant plant development on North Carolina s water supply. While there do not appear to be significant water supply issues with respect to the currently proposed merchant and utility plants, with perhaps the exception of the interbasin transfer for Dominion Person, the Commission may wish to obtain more information from DENR and other knowledgeable sources about future potential problems. A specific focus on the areas of the State where large natural gas pipelines and large electric transmission lines intersect may be advisable to determine whether and to what extent water supply problems could hinder in the future the construction of generation dedicated to serving North Carolina retail customers. 8 For example, in Docket No. SP-4, Sub 1, a State agency requested that the Commission impose a minimum release as a condition of the certificate. The applicant agreed, and the Commission imposed it on the certificate it granted. In 1990, in Docket No. SP-76, two State agencies, the Division of Water Resources and the Division of Parks and Recreation, asked the Commission to impose minimum release and canoe portage conditions on the requested certificate. After the hearing, but prior to the issuance of an order by the Commission, the FERC determined that it had jurisdiction over the project. As a result, the Commission did not rule on the proposed conditions, leaving them for the FERC to decide. 4-15

40 V. AIR QUALITY Over the next decade, electric generating plants will likely face significant federal requirements to further reduce emissions of sulfur dioxide (SO 2 ) and nitrogen oxides (NO x ) and new requirements to reduce emissions of mercury (Hg) and to reduce carbon dioxide (CO 2 ). In addition, in June, the General Assembly passed a bill that requires the lowering of SO 2 and NO x emissions from 14 North Carolina coal-fired power plants. This chapter first discusses federal requirements and implications and then discusses North Carolina-specific issues. A. FEDERAL Federal air pollution legislation was first passed in the mid-1950's. Today the federal government sets national emission standards for specific air pollutants and monitors the industry's compliance with those standards. A summary of federal legislation through the Clean Air Act Amendments of 1990 is attached at the end of this chapter as Attachment V-A. Since 1977, a major focus of federal legislation has been the creation of National Ambient Air Quality Standards (NAAQS). The United States Environmental Protection Agency (EPA) was created in the 1977 legislation to set and monitor the air quality standards. The States were required to implement these standards by designing, obtaining EPA approval for, and then enforcing State Implementation Plans (SIPs). The most recent comprehensive federal air pollution legislation is the Clean Air Act Amendments of 1990 (CAAA of 1990). Among other things, it established a permit program that is administered by the States. This is known as a Title V permit to operate. This permit contains numeric emissions standards specific to the particular source(s) at the permitted power plant. These standards apply at the stack exit and may include SO 2, NO x, particulate matter, opacity, and certain other chemicals. Part of this process 5-1

41 is a Phase II Acid Rain Permit, which is required for new fossil-fired combustion sources that sell electricity that is not otherwise exempt. The CAAA of 1990 also required large new sources to undergo New Source Review. For areas that are in attainment for all NAAQS, the standard is prevention of significant deterioration. This is accomplished through the requirement that a Prevention of Significant Deterioration (PSD) permit be obtained prior to the start of construction. PSD applicants must install best available emissions control technology (BACT) and demonstrate that emissions (after BACT) will have no significant impact on air quality. For areas not in attainment for one or more NAAQS, New Source Review requires the new source to install the lowest achievable emission rate technology and obtain emissions offsets at least equal to the amount of the emissions of the new source. To control acid rain, Title IV of the CAAA of 1990 created a two-phased plan to reduce SO 2 and NO x. Phase I ran from 1995 through 1999 and applied to specific generating units. (No plants in North Carolina were included.) Phase II, which began January 1, 2000, and included all other units, required additional reductions. With respect to emissions of SO 2 by electricity generators, emissions were required to be reduced approximately to 12 million tons by 1996, to 9.48 million tons per year between 2000 and 2009, and to 8.95 million tons per year thereafter. Because companies can bank allowances for future use, the long-term cap of 8.95 million tons per year may not be reached until after Ninety-seven percent of the SO 2 emissions produced by generators come from coal combustion. 1 1 The EIA s Annual Energy Outlook 2002, p

42 Larger, higher emitting generators were required to make reductions first. In Phase I, 261 generating units at 110 plants were issued tradable emissions allowances permitting SO 2 emissions to reach a fixed amount per year, which was generally less than each plant's historical emissions. Switching to low sulfur coal was the option chosen by most generators, with only about 12 GW of capacity being retrofitted with scrubbers by In Phase II, beginning in 2000, emissions constraints for SO 2 at Phase I plants were tightened, and limits were imposed for the remaining 2,500 boilers at 1,000 plants. Fuel switching and the use of allowances were the predominant responses to the Phase II limitations. The price of allowances is expected to increase significantly by 2005 and, at that level, 23 GW of capacity is expected to be retrofitted with scrubbers to meet the Phase II requirements. With respect to NO x emissions, the CAAA of 1990 required reductions also in two phases. The EPA was directed to issue regulations not later than May 1992 for certain boilers and by 1997 for all remaining boilers, with reduction requirements effective in 1995 and More stringent NO x emission reductions are required under various federal and state laws taking effect from 1997 to In addition, EPA has issued new standards for particulate matter and ozone. To reduce ozone formation, the EPA promulgated a multi-state summer season cap on power plant NO x emissions that will take effect in Particularly controversial have been interpretations of ozone transport studies. The States in the Northeast argued that emissions from coal plants in the Midwest make it difficult for them to meet national standards for ground-level ozone, and they petitioned the EPA to force coal plant operators to further reduce their emissions. The EPA proposed a NO x emissions cap for 22 Midwestern and Eastern States during the summer season. Following a court challenge, emissions limits were finalized for 19 States. These limits increase the operating costs of coal-fired, and, to a lesser extent, natural gas-fired generation plants. 2 Clean Air Act Handbook,: A Practical Guide to Compliance, Craig A. Moyer and Michael A. Francis, 3rd edition, Clark Boardman Callaghan,

43 Other pollutants also are being investigated. In December 2000, the EPA decided that mercury (Hg) emissions must be reduced. It plans to develop proposed regulations over the next few years. Emissions that lead to fine particles are being studied and may lead to new requirements. Finally, concern over emissions of greenhouse gases may lead to requirements that CO 2 emissions be reduced. As a result of several Congressional requests for the EIA to analyze proposed legislation for reductions of multiple emissions, the EIA has undertaken several analyses of the potential costs of various multi-emissions strategies to reduce air emissions from electric power plants. 3 This included a request that several different scenarios be examined with alternative reductions of SO 2, NO x, CO 2, and Hg emissions, with and without a renewable portfolio standard requiring a specified portion of all electricity sales to come from nonhydroelectic renewable fuels. The reference case for the study included the SO 2 and NO x reductions required by the CAAA of 1990, but did not include limitations on Hg or CO 2. The EIA s report notes that the key assumptions that influence projections when multiple emissions caps are modeled are the levels of the emission caps, the approach used to price electricity, and the response of the natural gas market to increased demand. A very interesting conclusion reached by the EIA in the study is that smaller increases in electricity prices are projected when it is assumed that prices in many regions of the country continue to be based on cost of service pricing. The price of electricity in 2010 is projected to be nine percent lower under that assumption than when the wholesale power market is assumed to behave competitively. The EIA analyzed a variety of alternative cases. Each case is set out in bold below with the EIA's findings with respect to each alternative set out just beneath. 3 Strategies for Reducing Multiple Emissions from Electric Power Plants. Another source of information is Reducing Emissions of Sulfur Dioxide, Nitrogen Oxides, and Mercury from Electric Power Plants, September

44 Alternative 1: Reducing Only Power Sector SO 2 and NO x Emissions 1. Reducing power sector SO 2 and NO x emissions to 75 percent below their 1997 levels is projected to lead to the installation of a large amount of pollution control equipment with little change in fuel use. 2. Power suppliers are projected to incur significant expenditures in order to comply with SO 2 and NO x caps, but electricity prices are expected to only be slightly higher as a result -- generally within one percent of the reference case level. Alternative 2: Reducing Power Sector Hg Emissions 1. Reducing power sector Hg emissions to 90 percent below their 1997 level is also projected to lead to the installation of a large amount of pollution control equipment. A shift in fuel use from coal to natural gas (a seven percent shift) also is projected because some coal-fired plants would not be operated as much if their generating costs were higher. 2. The cost and price impacts of reducing power sector Hg emissions are projected to be larger than those of reducing SO 2 and NO x emissions, with national average electricity prices projected to be three to four percent above reference case levels on average between 2010 and Requiring that maximum achievable control technology be used rather than an emissions cap and trade system reduces the effect on electricity prices, although they stay higher than in the reference case. 3. There is considerable uncertainty about the cost and performance of Hg removal technologies, which makes the above-described effects less certain. 5-5

45 Alternative 3: Reducing Power Sector CO 2 Emissions 1. When a cap on power sector CO 2 emissions is assumed, it is projected to have significant impacts on all aspects of the electricity production business. The key CO 2 compliance strategy is expected to be the retirement of coal-fired capacity in favor of natural gas and, to a lesser extent, renewables, as well as greater continued operation of existing nuclear power plants. Consumers are expected to reduce their use of electricity in response to higher electricity prices. 2. The electricity price impacts of meeting a CO 2 cap are much larger than those of meeting SO 2, NO x, and Hg caps. When a cap on power sector CO 2 emissions at seven percent below the 1990 level is assumed, average retail prices are projected to be 43 percent above reference case levels in Alternative 4: Establishing a Renewable Portfolio Standard (RPS) 1. A requirement that ten percent of all power sales must come from nonhydroelectric renewable fuels by 2010 and 20 percent by 2020 is projected to cause suppliers to use less natural gas and coal (i.e., to slow the expected increase in their use of those fuels). 2. Biomass, wind and geothermal resources are projected to provide most of the required increase in renewable generation. 3. The imposition of the above-described RPS (ten percent by 2010 and 20 percent by 2020) leads to slight reductions in power sector SO 2, NO x, and Hg emissions and a larger reduction in CO 2 emissions. 4. The renewable price credit, or subsidy, is projected to be between four and five cents per kwh. A 20 percent RPS is projected to lead to a four percent 5-6

46 increase in electricity prices by 2020 relative to the reference case because of the need to deploy higher cost renewable resources to meet the target. 5. Lower use of natural gas in the electricity sector when a 20 percent RPS is assumed is projected to lower average wellhead prices for natural gas in 2010 by seven percent and in 2020 by 17 percent, as compared to the reference case. Alternative 5: Reducing Power Sector SO 2, NO x, CO 2 and Hg Emissions without an RPS 1. The projected impacts of a power sector cap on CO 2 emissions dominate those of caps on other emissions. The key compliance strategy is a shift from coal to natural gas and, to a lesser extent, renewables, which will require costly capital additions. Consumers are expected to reduce their use of electricity in response to higher prices. 2. Higher natural gas prices and CO 2 allowance prices for electricity producers are projected to result in higher electricity prices for consumers percent higher than projected in the reference case in when SO 2, NO x, CO 2, and Hg caps are imposed. When less robust technology advancement assumptions for natural gas discovery and production are made, the projected price of electricity is eight percent higher. Alternative 6: Reducing Power Sector SO 2, NO x CO 2 and Hg Emissions with an RPS 1. Combining a 20 percent RPS requirement in 2020 with caps on SO 2, NO x, CO 2, and Hg is projected to reduce the shift to natural gas as a fuel for generation and increase the use of renewable fuels. The renewable credit price, or subsidy, is projected to be approximately three cents per kwh. 5-7

47 2. The switch to renewables leads to lower natural gas prices than would otherwise be expected. 3. The addition of the RPS to caps on SO 2, NO x, CO 2, and Hg emissions is projected to increase the resource costs of compliance by $21 billion over the 2000 and 2020 time frame, as compared to the costs without the RPS requirement. In 2010, electricity prices are projected to be 40 percent above the reference case level, as compared to 37 percent if the RPS requirement is not included. UNCERTAINTIES The EIA noted that there are a number of uncertainties that must be taken into account. Electricity prices could be substantially higher if the price of natural gas turned out to be higher than expected. In addition, the price impacts of the emissions caps are sensitive to assumptions about how electricity will be priced in the future and the policy instrument that is used to reduce emissions. There is substantial uncertainty about how various fuel markets might respond if significant shifts in the generating capacity and fuels used to produce electricity were to occur as projected, particularly as a result of the CO 2 caps. The degree to which consumers might respond to the projected price increase also is an uncertainty, as is the role new technologies might play. In addition, the EIA s study emphasized that careful planning would be needed in all cases to ensure that the reliability of the electric system would not be compromised during any transition period. B. NORTH CAROLINA The North Carolina EMC is the primary air quality regulatory agency in North Carolina. It typically adopts EPA regulations by reference or through separate rulemaking. The EMC has adopted all EPA ambient standards (the NAAQS) to date. As discussed above, federal law required each State to develop a State Implementation Plan, commonly called a SIP, which is essentially the state air quality regulations 5-8

48 needed to implement emissions standards and to ensure that NAAQS are achieved for the State. The Division of Air Quality in DENR enforces these standards in North Carolina. The General Assembly approved legislation in 1999 and 2000 aimed at reducing car and truck emissions, which are a major contributor to ozone smog. The use of lowsulfur gasoline statewide is required by January 2004 and the motor vehicle emissions testing program now required in nine counties would be expanded to 48 counties by July 2006, more incentives were provided for alternative fuel vehicles, and funding was increased for rail and mass transit. In 2001, the Division of Air Quality expanded its Air Awareness/Ozone Action Program from four to six metropolitan areas. Ozone forecasts are now available for Fayetteville and Hickory, in addition to the Charlotte, Triangle, Triad, and Asheville areas. North Carolina also has expanded its air quality monitoring network by adding 36 sites for measuring fine particulates under a new health-based standard that the EPA adopted in The State has about 190 monitors statewide for measuring various air pollutants, including 45 ozone monitoring sites. As noted in the introduction to this chapter, the General Assembly has passed a bill that requires the lowering of SO 2 and NO x emissions from 14 coal-fired generating plants owned by CP&L and Duke in North Carolina. The new law requires SO 2 emissions to be lowered to 250,000 tons by January 1, 2009, and to 130,000 tons by January 1, 2013, and NO x emissions to be lowered to 60,000 tons by January 1, 2007, and to 56,000 tons by January 1, The 14 affected plants are CP&L s Roxboro, Mayo, Sutton, Asheville, Lee, Weatherspoon, and Cape Fear plants and Duke s Belews Creek, Marshall, Allen, Cliffside, Dan River, Buck, and Riverbend plants. The map on the following page shows the locations of these 14 coal-fired plants. 5-9

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50 The top five facilities in terms of NO x emissions are as follows: (1) Belews Creek (Duke): 329 tons per day; (2) Roxboro (CP&L): 194 tons per day; (3) Marshal (Duke): 164 tons per day; (4) Allen (Duke): 59 tons per day; and (5) Mayo (CP&L): 55 tons per day. CP&L s Sutton plant also emits 55 tons per day, but it is excluded from the list because its NO x emissions are transported out to the Atlantic Ocean and do not impact North Carolina directly. 4 Natural gas-fired plants are less polluting than coal-fired plants and most of the alternatives discussed by the EPA either do not affect the use of natural gas for generation, or increase its use, as coal plants are used less often. Virtually every county in North Carolina is now included in the requirement that a Prevention of Significant Deterioration (PSD) review be conducted. This review determines whether a particular gas-fired merchant plant is required to install significant pollution control equipment and/or be issued an air permit containing significant restrictions on the number of hours that the plant can be operated. For areas not in attainment, more stringent controls and/or limitations can be required and imposed. The I-85 corridor of the State (minus the counties north of Wake County), plus Wake, part of Johnston, all of Harnett and all of Cumberland Counties are the areas of most concern for ozone nonattainment. (This is expected to include, to varying degrees, all or parts of the following counties: Union, Mecklenburg, Cabarrus, Gaston, Lincoln, Catawba, Iredell, Rowan, Davidson, Randolph, Forsyth, Guilford, Alamance, Orange, Durham, Wake, Johnston, Harnett, and Cumberland.) In addition, there are very small areas in a number of other counties that could face restrictions. C. CONCLUSIONS On a national basis, it is clear that electric generating plants will face significant requirements to further reduce SO 2 and NO x and new requirements to reduce emissions of mercury (Hg) and CO 2. North Carolina s newly imposed limits to reduce SO 2 and NO x should be a positive factor, with the caveat that there could be complications if issues 4 Governor Hunt s Clean Air Act Plan for North Carolina

51 are raised with respect to whether North Carolina's requirements interfere with the federal allowance trading program. It is unclear at this time which of the many identified alternative approaches for reductions, in addition to the existing SO 2 and NO x limitations and allowance trading program, will be taken at the federal level. On February 14, 2002, President Bush proposed an alternative to current EPA proposals, which he called The Clear Skies Initiative. It is billed as a multi-pollutant market-based approach to regulating power generation under the Clean Air Act. Overheads describing this new initiative are attached at the end of this chapter as Attachment V-B. The EPA s conclusion, discussed earlier in this chapter, that smaller increases in electricity prices because of pollution controls are projected when it is assumed that prices in many regions of the country continue to be based on cost of service pricing, is interesting because it runs counter to the assumption held by some that competition should always produce lower prices. The EPA projects the price of electricity in 2010 to be nine percent lower under cost-based pricing than when the wholesale power market is assumed to behave competitively. An additional factor to take into consideration is the potential impacts of pollution reduction requirements on reliability. The North American Electric Reliability Council (NERC) has undertaken some analyses of the impact on electric system reliability of the EPA's NO x emissions rules. Computer simulations showed small to significant impacts in the SERC Region, of which North Carolina is a part. These impacts varied, depending upon the length and timing of maintenance outages for the installation of pollution control equipment, and were viewed as highlighting the importance of having significant reserve margins. 5 5 "Reliability Impacts of the EPA NOx SIPs Call," Draft RAS NOx Study, Reliability Assessment Subcommittee of the North American Electric Reliability Council, February 2000; See also "Reliability Assessment ," North American Electric Reliability Council (October 2001), p

52 While it is difficult to predict exactly the nature and timing of additional restrictions and costs related to pollution controls affecting generation, the Commission needs to monitor developments in this area to ensure that needed utility plants can be built as they are needed and where they are needed to produce electricity on a least cost basis. This is an issue of some concern because the intersection of pipelines of sufficient size to fuel generating plants tend to be in the I-85 corridor (to Durham County), which already is the area of the State with the most serious pollution concerns. The reductions in SO 2 and NO x required by North Carolina's recently passed Smokestacks bill is likely to ameliorate this concern, although ultimately it will depend upon the nature and extent of the additional federal pollution limitations. Finally, efforts need to be made to ensure that the reductions in pollution that occur as a result of North Carolina s Smokestacks bill inure to the benefit of CP&L s and Duke s retail ratepayers, since they will bearing the vast majority of the costs through frozen rates and otherwise. 5-13

53 Appendix A Federal Legislation To Control Air Pollution Federal legislative efforts aimed at controlling air pollution in the United States began in the mid-1950's when Congress passed an act requiring the provision of research and technical assistance relating to air pollution control to the States. Since then, the Federal role in air pollution control has grown considerably, and today the Federal Government sets national emissions standards for specific air pollutants. It also monitors industry s compliance with these standards. The Clean Air Act Amendments of 1990 is the latest air pollution control legislation enacted by the U.S. Congress. Other Federal legislation controlling air pollution includes the Clean Air Act of 1963, the Air Quality Act of 1967, the Clean Air Act Amendments of 1970 and 1977, and various additional amendments and extensions of the Clean Air Act passed in 1971, 1973, 1974, and 1976 (Table A1). Table A1. Chronology of Historic Federal Legislation To Control Air Pollution Legislation and Date An Act To Provide Research and Technical Assistance Relating to Air Pollution Control (1955) Clean Air Act of 1963 Air Quality Act of 1967 Clean Air Act Amendments of 1970 Amendments and extensions of Clean Air Act (1971, 1973, 1974, 1976) Clean Air Act Amendments of 1977 Clean Air Act Amendments of 1990 Role of Federal Government Provide research, technical, and financial aid to States Mediate among States, if requested Create air quality control regions; establish criteria for health protection; recommend control techniques; set national emissions standards for vehicles Set national primary and secondary air quality standards; review and approve State implementation plans; assess hazards from additional named pollutants; set national emissions standards for stationary sources; set statutory reductions and timetable for vehicle emissions; regulate fuels, fuel additives, aircraft emissions, noise Establish waivers and extensions of motor vehicle emissions standards Classify air quality control regions as attainment or nonattainment; establish program for prevention of significant deterioration; provide special treatment for eastern coal; strengthen new source performance standards and hazardous pollutant sections; tighten motor vehicle emissions standards. Establish new provisions designed to reduce emissions of SO 2. Establish an allowance system, based on a nationwide limit of 8.9 million tons of SO 2 per year. Establish a list of 189 regulated hazardous air pollutants. Require all major sources of air pollution to obtain an operating permit. Strengthen enforcement provisions for EPA. Sources: Lester B. Lave and Gilbert S. Omenn, Clearing the Air: Reforming the Clean Air Act (Washington, DC: Brookings Institution, 1981), p. 6. Environmental Law Institute, Clean Air Deskbook (Washington DC, March 1992) and Clean Air Act Handbook, A Practical Guide to Compliance, Third Edition, Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update 59

54 An Act To Provide Research and Technical Assistance Relating to Air Pollution Control Passed in 1955, an Act To Provide Research and Technical Assistance Relating to Air Pollution Control was, in part, a response to the growing concentration of the U.S. population in urban areas, many of which were spread over more than one State (e.g., New York, Chicago, and Washington, D.C.). Congress found that the growth in the amount and complexity of air pollution brought about by urbanization, industrial development, and the increasing use of motor vehicles, had resulted in mounting dangers to the public s health and welfare, including injury to agricultural crops and livestock, damage to and the deterioration of property, and hazards to air and ground transportation. The 1955 act sought to remedy the growing air pollution problem by supporting research and providing information and financial aid to the States. The act expressly acknowledged the primary responsibilities and rights of State and local governments to control air pollution. The Federal Government had no direct regulatory role. The Clean Air Act of 1963 The Clean Air Act of 1963 began to expand the role of the Federal Government in curbing air pollution by including direct regulation. Air pollution that endangered the health or welfare of any persons was made subject to abatement under certain circumstances. The law provided two additional tools for use in the fight against air pollution. Federal funds were to be made available to State and local pollution-control agencies, and, because the effects of air pollution often crossed State boundaries, the negotiation of interstate compacts establishing joint control agencies was authorized. The Air Quality Act of 1967 The Air Quality Act of 1967 further extended the role of the Federal Government into air pollution standards. It authorized the Secretary of Health, Education, and Welfare to create air quality regions and establish criteria for setting air quality levels that would protect public health. The States were required to adopt ambient air quality standards consistent with these criteria. The Clean Air Act Amendments of 1970 The Clean Air Act Amendments of 1970 substantially expanded the Federal role in air pollution control. The act came about because, with the exception of California, State and local governments had taken only limited action to control air pollution. Congress decided that the National Ambient Air Quality Standards (NAAQS) were the appropriate criteria for protecting public health, and it dismissed the relevance of abatement cost in setting the standards. The newly created Environmental Protection Agency (EPA) was given responsibility for setting the standards. The States implemented the program by designing, seeking EPA approval for, and then enforcing State Implementation Plans that would ensure attainment of the NAAQS by Standards were promulgated for 6 criteria pollutants: particulate matter, sulfur oxides, carbon monoxide, nitrogen dioxide, ozone, and nonmethane hydrocarbons. A standard for lead was added in 1978, and the standard for ozone was revised in All of these standards are still in place. For enforcement purposes, the United States was divided into 274 air quality control regions. NAAQS limits were required to be met in each region. Control regions within State boundaries where the ambient pollutant concentrations were below or met the NAAQS were designated as attainment areas by the 1970 amendments. Conversely, areas where the ambient pollutant concentrations did not meet NAAQS were labeled nonattainment areas. Distinct from ambient standards, the 1970 amendments also introduced national emissions standards for new stationary sources of air pollution, limiting the amounts of sulfur dioxide (SO 2), nitrogen oxides (NO X), and particulates that coal-fired boilers of certain classes could emit. In general, these technology-based standards called for the application of the best available control technology, under which Congress did allow some consideration of the cost of the abatement. However, Congress imposed stringent deadlines for achieving national standards. The Clean Air Act Amendments of 1977 The Clean Air Act Amendments of 1977 further emphasized the classification of air quality control regions as attainment or nonattainment areas with regard to all established ambient air standards. Sanctions and special implementation strategies were introduced for nonattainment areas. The amendments stipulated that sources in nonattainment areas must use reasonably available pollution control technologies, taking into consideration both cost and technological feasibility. The amendments also imposed new requirements on areas already in attainment. The concept of prevention of significant deterioration (PSD) was introduced whereby 60 Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update

55 the amendments established specific increments for maximum allowable increases in ambient concentrations for three classes of PSD areas. The PSD program included a permit program for new major emission sources and modifications to existing sources. It required sources to apply best available technology, which would be determined case by case. The Clean Air Act Amendments of 1990 The 1990 amendments establish a list of 189 regulated hazardous air pollutants. EPA is required to establish standards for major sources, which are defined as those with the potential to emit 10 tons per year of any single hazardous pollutant or 25 tons of any combination of pollutants. The amendments establish a new permit program whereby all major sources are required to obtain an operating permit. States with approved permitting programs issue permits, but EPA has the power to veto State permits. Citizens also have certain rights to challenge State permits. The 1990 amendments also establish the Acid Rain Program, which is designed to reduce the adverse effects of acid deposition. This improvement will be achieved primarily through reductions of SO 2 and NO x emissions by electricity producers, while concurrently encouraging energy conservation and the use of renewable and clean alternative technologies in electricity production. The primary goal of the Acid Rain Program, which will be nstituted in 2010, is to reduce annual SO 2 emissions from electric utilities to a level that is 10 million tons below the 1980 level. Emission allowances serve as the mechanism for compliance. Each affected unit is allocated its allowances based on its baseline fuel consumption. The baseline is calculated from the average yearly fuel consumption for the period In Phase I, allowances are allocated at the rate of 2.5 pounds of SO 2 times the number of mmbtu consumed in the baseline. In Phase II, allowances are allocated at the rate of 1.2 pounds of SO 2 times the number of mmbtu consumed in the baseline. The legislation also requires a reduction of 2 million tons of NO x emissions from utility boilers. Utilities were required to apply low-no burner technologies to meet x regulations that become effective on the date the unit must meet the SO standard, i.e., January 1, 1995, for 2 Phase I units; January 1, 1997, for Phase I units employing scrubber technology; and January 1, 2000, for all Phase II units. However, a lawsuit pushed the date of compliance back to January 1, 1996, for the Phase I units that had been required to be in compliance on January 1, NO x limits for dry-bottom, wall-fired and tangentially fired boilers affected in Phase I have been selected as 0.50 pounds per million Btu and 0.45 pounds per million Btu, respectively. Regarding Phase II compliance, NO limits x must be established by no later than January 1, 1997, for two categories of boilers exempted from Phase I: cell- and cyclone-fired units. Also by that date, the limits for drybottom, wall-fired and tangentially fired boilers can be revised, if EPA deems it feasible with new technology. An emissions averaging provision allows individual utilities to average NO emissions over multiple units, if the same x or lower emissions result. Energy Information Administration/ The Effects of Title IV of the Clean Air Act Amendments of 1990 on Electric Utilities: An Update 61

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61 VI. TRANSMISSION The Commission s Order requesting the Public Staff to investigate the availability and adequacy of the infrastructure in North Carolina to support future electric generation included a consideration of electric transmission requirements. The area of electric transmission is very complex and technically challenging. The effects of merchant generation may very well ultimately prove to be the most negative in this area, but it is the hardest area in which to identify and quantify constraints and their effects. This is complicated further by jurisdictional conflicts between the FERC and the States and the various changes in policy direction at the FERC. This chapter is organized as follows: The first section discusses reliability, first in terms of reliability organizations and then in terms of certain key features of electric industry infrastructure. The second section discusses recent FERC initiatives, starting with Order No. 888 in 1996 and concluding with the forthcoming Standard Market Design Notice of Proposed Rulemaking. The current status of transmission, proceedings before the Commission, and conclusions follow in subsequent sections. A. RELIABILITY 1. RELIABILITY ORGANIZATIONS (a) NERC In 1968, following widespread black-outs in the Northeast in November 1965, the electric industry voluntarily established a not-for-profit corporation to promote electric reliability and security. Called the North American Electric Reliability Council (NERC), this organization has operated as a voluntary organization since that time and has helped make the North American electric system the most reliable system in the world. According to its web site, NERC does the following, in promoting electric system reliability and security: 1 1 NERC s web site address is 6-1

62 Establishes operating policies and planning standards to ensure electric system reliability; Reviews the reliability of existing and planned generation and transmission systems; Critiques past electric system disturbances for lessons learned and monitors the present for compliance and conformance to its policies; Educates others about how bulk electric systems operate; Maintains liaisons with the federal, state, and provincial governments in the United States and Canada and with electricity supply industry organizations in both countries; and Serves as the electric industry s primary point of contact with the federal government on issues relating to national security and terrorism. Also according to NERC s web site, the growth of competition and the structural changes taking place in the industry have strained the voluntary nature of the organization. In response to these changes, NERC is in the process of transforming itself into an industry-led self-regulatory reliability organization (SRO). Compliance with reliability rules currently is mandatory but NERC lacks authority to enforce it. NERC has proposed federal legislation that would give NERC the statutory authority to enforce compliance. The energy legislation passed by the United States Senate in April 2002 contains key elements of the NERC reliability proposal. This legislation is intended to ensure that a new reliability organization and its affiliated regional entities would operate efficiently and would expressly protect the important roles of the States and regions. The House energy legislation did not contain any provisions relating to reliability. NERC is hopeful that the House-Senate conference committee will adopt the Senate's version. In the meantime, NERC has developed agreements for regional compliance and enforcement with its members. 6-2

63 NERC s members are ten Regional Councils that cover the United States, most of Canada, and a small part of Mexico. The members of these councils come from all segments of the electric industry. The ten Regional Councils, in alphabetical order, are as follows: (1) ECAR (East Central Area Reliability Coordination Agreement), which includes Wisconsin, Indiana, Ohio, Kentucky, West Virginia, southwestern Virginia, and a small part of western Pennsylvania; (2) ERCOT (Electric Reliability Council of Texas), which covers most of Texas; (3) FRCC (Florida Reliability Coordinating Council), which consists of Florida, except for the westernmost part of the panhandle; (4) MAAC (Mid-Atlantic Area Council), which includes most of Pennsylvania and Maryland, all of New Jersey, Delaware, and D.C., and a small part of Virginia; (5) MAIN (Mid-America Interconnected Network, Inc.), which covers Illinois, part of Missouri, part of Iowa, a small part of southeastern Minnesota, and part of Michigan; (6) MAPP (Mid-Continent Area Power Pool), which includes Nebraska, most of South Dakota, a very small part of eastern Montana, North Dakota, most of Minnesota, part of Michigan, part of Iowa, and the provinces of Manitoba and Saskatchewan, Canada; (7) NPCC (Northeast Power Coordinating Council), which includes New York, all of the New England states, and the eastern half of Canada, from Ontario eastward; (8) SERC (Southeastern Electric Reliability Council), which includes most of Virginia, all of North Carolina, South Carolina, Georgia, Tennessee, Mississippi, and Alabama, part of Louisiana, a tiny portion of eastern Texas, most of Arkansas, and part of Missouri; (9) SPP (Southwest Power Pool), which includes part of Louisiana, several very small pieces of Texas, western Arkansas, Oklahoma, Kansas, and a very small part of eastern New Mexico; and (10) WSCC (Western Electricity Coordinating Council), which includes a tiny piece of western Texas, most of New Mexico, all of Arizona, California, Nevada, Utah, Colorado, and Wyoming, a small part of western South Dakota, most of Montana, all of Idaho, Oregon, and Washington, the provinces of Alberta and British Columbia, Canada, and the northern portion of Baja California Norte, 6-3

64 Mexico. All of the Regional Councils, except ERCOT and WSCC, are in the Eastern Interconnection, which extends from the East Coast to the Rocky Mountains (excluding most of Texas). The Eastern Interconnection is comprised of over 100 transmission systems, most of which constitute their own control area. The WSCC constitutes the entire Western Interconnection, just as ERCOT, the reliability council, constitutes the ERCOT Interconnection. According to NERC s Operating Manual, the Western Interconnection has several direct-current (one direction only) connections and ERCOT has two direct-current connections to the Eastern Interconnect. The map on the following page shows the three interconnections and the locations of the ten Regional Reliability Councils within them. 6-4

65 Regional Councils

66 (b) SERC According to NERC s web site, SERC is the largest of the NERC regions, as measured by total generation and load. It covers an area of about 464,000 square miles and includes parts or all of 13 southeastern and south central states. The region divides itself into four diverse Subregions: Entergy (the geographical area covered by the Entergy Operating Companies and Associated Electric Cooperative, Inc.); Southern (the geographical area covered by the Southern operating companies); TVA (the Tennessee Valley Authority area), and VACAR (the Virginia-Carolinas area). SERC is directly interconnected with transmission systems in ECAR, FRCC, MAAC, MAIN, and SPP. The VACAR Subregion is directly interconnected only with ECAR and MAAC. According to SERC s web site, the purpose of the coordination of the operation and planning of the bulk power electric systems in the southeastern United States is to ensure that the individual electric systems do not adversely affect other systems and that opportunities for improved system performance are identified. SERC replaced four loosely organized groups in 1970, when 22 electric systems signed the SERC Agreement. Because of the geographic size of the Region and the diversity among its parts, it was divided into four subregions for data reporting purposes: VACAR, TVA, Southern, and the Florida Peninsula. In September 1996, Florida became a separate NERC Region. Effective January 1, 1998, the operating companies of Entergy and two cooperatives joined SERC as a fourth subregion. The Preamble to SERC s Principles and Guides for Reliability in System Planning states that SERC recognizes that the reliability of power supply in local areas is the responsibility of the individual SERC members and that each system has its own internal criteria relating to load forecasting, resource planning, and transmission planning. The criteria in the SERC document are a resource to use in conjunction with local area criteria. SERC's "Principles and Guides" document defines reliability as the degree to which the performance of the elements of a system results in power being delivered to consumers within accepted standards and in the amount desired, indicating that the degree of reliability 6-7

67 may be measured by the frequency, duration, and magnitude of adverse effects on consumer service. The SERC section of NERC s Reliability Assessment shows SERC as having a total of 28,453 miles of transmission lines as follows: 19,222 miles of 230 kv lines, 784 miles of 345 kv lines, and 8,447 miles of 500 kv lines. Planned transmission additions include 2,415 miles of 230 kv and 369 miles of 500 kv lines, for a total of 2,784 miles over the next ten years. VACAR is shown as having 11,890 miles of transmission lines (230 kv and above) and planning to add 661 miles of transmission lines (230 kv and above). The Southeastern Infrastructure Assessment report prepared by the Southeastern Association of Regulatory Utility Commissioners (SEARUC), dated April 22, 2002 (Southeastern Infrastructure Assessment), shows SERC having slightly different totals of transmission lines. This report shows the existing and planned miles of transmission lines (230 kv and above), by subregion, as follows: Subregion Existing Planned ( ) Entergy 5, Southern 11,046 1,215 TVA 2, VACAR 11, TOTAL 30,541 2,097 The majority of transactions by the electric utilities within SERC are bundled retail sales. The FERC's November 1, 2000, Staff report, "Investigation of Bulk Power Markets - Southeast Region," acknowledges that the Southeast has far fewer wholesale transaction than many of the other regions of the country and that the majority of them are at costbased rates. As the Commission noted in various of its filings with the FERC, 90 percent or more of the electricity used to serve North Carolina customers comes from within the control areas of North Carolina's electric utilities. In addition, there are few planned purchases and sales of power between the subregions of SERC, and relatively few with 6-8

68 other Regions. SERC's 2002 Summer Assessment indicates that planned transactions outside the Region scheduled for the summer of 2002 include 3,312 MW in purchases and 1,939 in sales, resulting in a net purchase from outside the SERC Region of 1,373 MW. According to this same report, SERC has total installed operable capacity of 174,548 MW. (c) VACAR According to the Southeastern Infrastructure Assessment, the VACAR subregion of SERC is the largest of the subregions with respect to generation capacity and miles of transmission lines. It has a projected reserve margin of 14 to 20 percent through 2010, without including any of the proposed merchant generation. (It has not been included because it has not been committed to retail load in the SERC region.) As shown above, VACAR has planned additions of 505 miles of transmission lines through It is directly interconnected with the ECAR and MAAC Regions and with the TVA and Southern subregions of SERC. CP&L, Duke and NC Power are all members of VACAR, along with South Carolina Electric & Gas Company (SCE&G) and the South Carolina Public Service Authority (SCPSA or Santee Cooper). CP&L s transmission system consists of approximately 6,000 miles of transmission lines (down to 44 kv in size) and just over 100 transmission-class switching stations in its North and South Carolina service areas. CP&L has transmission interconnections with AEP (ECAR Region), Duke, TVA, NC Power, SCE&G, SCPSA, and the Yadkin Division of Alcoa Power Generating Inc. (Yadkin, which supplies electricity mainly to an affiliated industrial plant from its own nearby hydroelectric facilities in and around Stanly County). Duke s electric transmission system is composed of more that 12,500 miles of electric transmission lines (down to 44 kv in size) in its service territory in central and western North and South Carolina. Duke has interconnections with Southern, the Southeastern Power Administration, SCE&G, SCPSA, CP&L, AEP (ECAR Region), TVA, and Yadkin. 6-9

69 NC Power's electric transmission system is composed of 6,000 miles of transmission lines. 2 It has 976 miles of 115 kv and larger lines in its North Carolina service territory, 3 which covers northeastern North Carolina. It is interconnected with CP&L, AEP (ECAR Region), Allegheny Power (ECAR Region), and PJM (MAAC Region). As described by North Carolina s utilities in their filings in Docket No. E-100, Sub 94, their first objective is to provide an adequate transmission system to serve the native load of their service territories. The transmission systems of CP&L, Duke and NC Power (including lines in South Carolina and Virginia) are shown on a two-page map that is attached at the end of this chapter as Attachment VI-A. As is discussed in some detail below, power system operations in the United States are built upon the concept of multiple control areas, each functioning independently, but coordinating operations. CP&L, Duke, and NC Power all constitute independent control areas. As such, they each monitor and control their own transmission systems and their own generation. In its initial comments in Docket No. E-100, Sub 94, CP&L stated that its system operators monitor its transmission system 24 hours a day, seven days a week. These system operators monitor real-time flows and are trained to respond to minimize the adverse impact of unexpected conditions or events. In its initial comments, Duke stated that it optimizes operations by closely monitoring the entire system and balancing customer load moment-by-moment with the system s generating capacity. The utilities plan their generation and transmission systems on an integrated basis, that is, they each optimize the location and capacity of their generating units to match the configuration of the transmission grid and vice versa. They build and maintain both generation and transmission reserves for growth and contingencies. 2 Alliance RTO Presentation, May Application for Authority to Transfer Functional Control of Transmission Assets to the Alliance Regional Transmission Organization, filed in Docket No. E-22, Sub 391, on September 21, NC Power filed a motion to withdraw this application on January 11, 2002, which was allowed by Commission Order dated January 17,

70 Duke also filed its Duke Electric Transmission System Planning Guidelines as Exhibit 3 to its initial comments in Docket No. E-100, Sub 94. These guidelines indicate that a 1,100 MW first contingency incremental transfer capability level into the Duke system from VACAR is supposed to be maintained to allow the import into Duke from CP&L, SCE&G, SCPSA, and NC Power of shared contingency reserves. Similarly, Duke maintains a minimum first contingency incremental transfer capability exports from the Duke system of 600 MW each to CP&L, SCE&G, SCPSA, and NC Power. In addition to the utilities' system operators, there are now two security coordinators within VACAR who monitor real-time flow on critical flowgates and may institute transmission loading relief (TLR) procedures to curtail scheduled power deliveries as needed to reduce facility loading to an acceptable level. Duke serves as the security coordinator for the VACAR South interface. NC Power performs this function for the VACAR north interface. 2. KEY FEATURES OF ELECTRIC INDUSTRY INFRASTRUCTURE Electric industry infrastructure is fundamentally different from all other large infrastructure systems, such as natural gas pipelines and telephone networks. It has two unique characteristics: (1) there must be continuous and nearly instantaneous balancing of generation and load, consistent with transmission network constraints, primarily because electricity cannot be stored easily; and (2) the transmission network is passive, with control actions limited primarily to limiting generation outputs and to opening and closing switches. 4 Because there is high degree of interdependence between generation and transmission that cannot be avoided, careful planning and coordination between generation and transmission within a control area is a necessity. 4 Reliability Considerations in Electric Industry Restructuring, prepared by Research Triangle Institute for the Legislative Study Commission on the Future of Electric Service in North Carolina, March 1999, Appendix A. Its principle authors were John A. Casazza, CSA Energy Consultants, Inc., Dr. Eric Hirst, and P. Jeffrey Palermo, CSA Energy Consultants, Inc. 6-11

71 NERC addresses electric system reliability by considering two basic and functional aspects of the electric system adequacy and security. Adequacy is defined as the ability of the electric system to supply aggregate demand and energy requirements of its customers at all times, taking into account scheduled and reasonably expected unscheduled outages of system elements. Security is the ability of the electric system to withstand sudden disturbances, such as electric short circuits or unanticipated loss of system facilities. In plainer terms, an adequate system has sufficient generation and transmission resources available to meet projected needs plus reserves for contingencies, while a secure one has sufficient equipment and procedures in place to withstand disturbances, such as adverse weather and equipment failures. Both encompass elements of operations and planning, with adequacy issues tending to be long term in nature (e.g., siting and constructing a transmission line) and security issues typically involving short term conditions and reactions. Adequacy and security can each be maintained at the expense of the other. A power system can serve its full load (i.e., be adequate) by using up all reserves, but the resulting risk is that the system would not survive a severe contingency. On the other hand, a power system can maintain security by curtailing load (i.e., be inadequate) in order to maintain generation and transmission reserves to protect the system against contingencies. All power systems must balance adequacy and security to provide reliable service. The existence of contingency reserves (both generation and transmission) and operating rules to govern the use of these reserves are the primary mechanisms to mitigate the risks associated with unexpected events. For example, because the failure of either a generating plant or a transmission line can affect all load, reserves must protect against both contingencies. Either reserve generation must be located near loads (so the transmission line contingency is eliminated) or a combination of remote generation and reserve transmission must be maintained. 5 5 "Reliability Management and Oversight," Brendan Kirby and Eric Hirst. 6-12

72 As stated earlier, the United States power system operations are built upon the concept of multiple, independently functioning control areas. A control area is usually a contiguous grouping of generating units, transmission lines, transformers and loads under the supervision and control of a single operator or under a single administrative structure. Flows of power across control area boundaries are always metered and monitored. Every location with electric service is assigned to a control area, and every control area is responsible for balancing its generation with its load because the amount of electricity generated must equal the amount consumed, plus losses. In addition, imports and exports must be precisely measured so that it can be determined that an area is balancing its generation and load. To be recognized as a control area, a system must operate generation, have metered connections with other control areas and the ability to use them, have the ability to control generation and match actual interexchange with scheduled interexchange, and have a control center with 24-hour a day staffing. All control areas are expected to operate their bulk electric systems (generation and transmission) according to NERC s Operating Policies. CP&L, Duke and NC Power all qualify and operate as control areas. The ability of each individual electric system (i.e., control area) to transfer electric power between and among the other electric systems with which they are interconnected, while delivering power from generation sources to customers within the system, may be limited by the physical and electrical characteristics of each of the systems. These include limits on thermal ratings (i.e., how much load can be put on the line or other component of the transmission system), voltage levels, and the stability of the network. When these limits are reached, the load on the stressed line(s) must be reduced, which leads to curtailments (starting with the least firm service) and the denial of service for new transactions. Because the flow of electricity among transmission circuits is determined by the laws of physics, not by commercial schedules, a greater number of transactions, in different locations and of different sizes, than contemplated when the various transmission systems were designed and constructed, makes it very difficult to quantify the availability of capacity on a given transmission system at any given time. As noted in an article in the August 1997 edition of "Electrical World," a 100 MW transfer from Oregon to Utah under a 6-13

73 contract path through Idaho actually flows in all directions with 33 percent of the power flowing through California. 6 These inadvertent flows are often called parallel path flows. NERC s policies, standards, and requirements require all transmission systems to be capable of operating without exceeding the thermal, voltage, and stability limits of the system and of each of its components, during both normal and contingency conditions. All transmission systems must be planned, designed and constructed to maintain all loads on equipment within the thermal, voltage and stability limits for either normal operations or under the loss of any one of the following: (1) a single transmission circuit; (2) a single transformer; (3) a single generating unit; (4) a single reactive power source or sink; (5) the combination of a single generating unit and a single transmission circuit, capacitor bank, or transformer; or (6) the combination of two generating units. 7 Each utility is responsible for the operation of its own control area. It coordinates its transmission planning and operations with neighboring systems to assure the safety, reliability, and economy of its power system. Each utility is required to plan its system so that it does not rely excessively on or cause an undue burden on neighboring systems. Coordinated near-term operating studies and longer-range planning studies are made on a regular basis to ensure that transmission capacity will continue to be adequate. Transmission facilities are comprised of a series of current carrying components, such as each span in the transmission line, transmission transformers, jumpers, bus work, 6 Power Traders: Do You Have Any Idea Where the Power Goes? by William Kock, PE, Contributing Editor, Electrical World, August 1997, p. 40, reporting on John A. Cassaza s report: Electrical World Executive Report, published in May 1997, on the causes of the 1996 outages in the Western states. 7 Transmission Expansion: Issues and Recommendations, NERC (February 20, 2002), p. 4, See also, NERC Planning Standards, which are available on NERC s web site. 6-14

74 switches, current transformers, ammeters, and relays. The outage or failure of any one of these components would cause the outage or failure of the facility. Each individual component has a thermal rating which limits its ability to reliably carry current and transfer energy. This thermal rating is a function of its design, construction, the temperature of its surroundings during operation, and adherence to various safety requirements. The overall rating of the transmission facility is the lowest rating of the individual components. If a transmission facility loading expected to exceed its thermal rating is identified, then possible solutions include (1) upgrading each individual component whose rating is below the expected loading, (2) making changes to system configuration, and (3) constructing new transmission facilities. 8 Similar processes are undertaken for an identified violation of voltage guidelines, and similar analyses are performed to ensure system stability limits are met. With respect to planning, NERC's requirements establish certain parameters that have to be met. All three of the North Carolina utilities develop a long-range transmission plan that provides for orderly and timely modifications to the transmission system to insure an adequate, economical and reliable supply of electric power to the control area. Each utility's transmission planning process and generation resource planning process are interrelated because the location and availability of generation additions have significant impacts on the adequacy of the transmission system. Generation additions within each utility s system may help or hinder transmission loading. Because there is high degree of interdependence between generation and transmission that cannot be avoided, careful planning and coordination between generation and transmission within a control area is a necessity. In addition, by planning for both generation and transmission needs, a utility also is able to minimize costs. Because of the interconnectedness of the grid of transmission systems, planning and coordination on a wider scale also is required. It is universally acknowledged that the majority of the transmission systems in the United States were explicitly designed for local purposes. The primary purpose of the transmission systems in North Carolina, as they were and are designed and used, is to 8 Duke s initial comments filed in Docket No. E-100, Sub 94, p

75 provide the electrical path necessary to transfer bulk power from local generating plants over fairly short distances to local demand centers, as needed to ensure safe, reliable, and economic service to control area customers. The interconnections among neighboring control areas were intended only to provide limited power and reserve sharing among neighboring utilities. 9 With electric industry restructuring, the transmission systems in the United States are being used increasingly for long distance transactions, often of a sporadic, temporary, and often unpredictable nature. The FERC's attempts to "jump start" competitive wholesale markets have led to increased stress on the transmission grid. Similarly, the FERC's encouragement of merchant plants choosing locations that are to their own advantage (i.e., close to fuel, for example, rather than close to loads), rather than being based on transmission system considerations, has increased those levels of stress. These issues are discussed in Section C, after the following discussion of the FERC's various electric industry restructuring initiatives. B. FERC INITIATIVES Until the enactment of the Energy Policy Act of 1992 (EPACT), most electric service in the United States, both wholesale and retail, was provided on a bundled basis (i.e., as one packaged product, not as separate services). The FERC was regarded as lacking the authority to require a utility to provide transmission service separate from generation service for wholesale customers, except indirectly as a condition of approval of a merger or market based rates. The FERC s regulation of interstate transmission as a distinct service was basically limited to transmissions involving the transporting of emergency and economy transactions to and from utilities separated by one or more intervening control areas. EPACT gave the FERC the authority to require the separate transmission of electricity to wholesale customers, but explicitly provided that (1) transmission capacity could be recalled for retail native load customers, (2) the provision of transmission service 9 See, e.g., NERC's "Transmission Expansion: Issues and Recommendations Report; NERC s May 2001 National Energy Policy report; and FERC's Order

76 was excused if needed expansions could legitimately not be accomplished, and (3) new transmission users would be required to pay for expansions, to the extent practicable, not existing retail, wholesale and transmission customers ORDER NOS. 888 AND 889 In 1996, the FERC issued Order Nos. 888 and 889 requiring all jurisdictional utilities to provide open access transmission service to wholesale customers and establishing an Open Access Same-Time Information System (OASIS) to provide information about transmission availability, respectively. All utilities were required to file standard (pro forma), nondiscriminatory open access transmission tariffs (OATT) that were available to all wholesale customers. The rules adopted by the FERC in Order No. 888 required utilities to separate (i.e., unbundle) their transmission functions from their power marketing functions related to wholesale transactions. They also required utilities to obtain information about their own transmission system for their own wholesale sales from OASIS to prevent them from having an unfair advantage over competing generators. Utility employees separated from the wholesale marketing function were required to calculate and post the total transfer capability (TTC) of the utility's system, which is the total amount of electric power that can be transferred over the interconnected transmission network in a reliable manner, and the available transfer capability (ATC), which is a measure of the transfer capability remaining in the physical transmission network for further commercial activity over and above already committed uses. When there is insufficient ATC to accommodate all requests to send electricity over a given path (from seller to buyer), congestion, or bottlenecks, result. Because electricity cannot be stored economically, transmission system operators must deny requests for service when they receive too many of them and curtail transactions previously granted if inadvertent power flows cause unexpected congestion U.S.C.A. 824j and 824k. 6-17

77 2. ORDER NO In December 1999, the FERC issued Order No to build upon the greater level of competition in the wholesale market caused by Order No Order No encouraged transmission owners to voluntarily join regional transmission organizations (RTOs) to help address the economic and engineering inefficiencies the FERC believed are inherent in current transmission systems and to correct perceived and real discrimination by transmission owners that also own generation against competing generators. Utilities were required to file either to join an RTO by October 15, 2000, or an explanation as to why no such filing would be made. The FERC did not require participation or draw boundaries for any RTOs. December 15, 2001, was the proposed operational date for all RTOs. Per Order No. 2000, RTOs must be independent, have sufficient scope and configuration to effectively perform its functions, coordinate security for its region, and have exclusive authority for maintaining short-term reliability of the transmission systems it operates. In addition, the FERC identified eight functions that RTOs must perform, as follows: (1) being the tariff administrator and designer, (2) managing congestion, (3) addressing parallel path flows, (4) being the provider of last resort for ancillary services, (5) administering OASIS, (6) monitoring the markets it operates, (7) planning and directing necessary expansions and upgrades, and (8) developing mechanisms to coordinate with other regions. In its filings at the FERC in response to Order No. 2000, Duke argued that if unbundling is required, State consent may take some time to acquire, as there are numerous considerations that a State must take into account. Duke warned that the issues are more complex than which regulatory body regulates the revenue requirement. Duke noted that the functions that the FERC proposed be transferred to an RTO include the following: (1) ultimate control over generation redispatch; (2) control over realtime balancing; (3) authority to manage congestion, which necessarily affects retail service costs of generation; and (4) control over system reliability, all of which are integral 6-18

78 components of retail electric service under State jurisdiction. In sum, Duke argued, the RTO would disaggregate its members' integrated transmission and generation systems and take over the system operations functions for both wholesale and retail loads. Duke questioned whether this could be done under current law without the consent of each affected State. In addition, Duke argued the filing and proposed operational deadlines were too short because States must have ample time to consider such a transfer because of the tremendous impact of the proposed jurisdictional shift. Duke recommended that utilities be allowed to transition to RTO membership in a manner that is coordinated with retail service restructuring and unbundling. The FERC rejected Duke's arguments and similar arguments of many others, mainly on the ground that RTO formation and membership were voluntary. (a) GridSouth CP&L, Duke, and SCE&G made a timely filing with the FERC to form GridSouth Transco, LLC (GridSouth), a Carolinas-based RTO. In March 2001, the FERC provisionally approved GridSouth, but refused to permit certain provisions the utilities had included to keep retail service bundled and to keep authority for planning and expanding for their retail customers' needs. On April 13, 2001, the utilities filed for clarification and rehearing on the proposals rejected by the FERC, which was denied by FERC Order dated May 30, The utilities were directed to make further filings consistent with the Order. On July 12, 2001, the FERC ordered the GridSouth applicants and all other jurisdictional utilities in the Southeast to mediation for the purpose of forming one RTO for the Southeast. 11 A subsequent report by the Administrative Law Judge assigned to serve as the mediator was not acted upon. While the FERC apparently has not given up its goal of having one Southeast RTO, it now seems to be more open to several smaller RTOs in the Southeast. Because of other developments, however, GridSouth currently is on hold. The Commission challenged the FERC's GridSouth orders on numerous legal, jurisdictional, and policy grounds, including the lack of adequate notice and other 11 The FERC also required mediation for the formation of one RTO in the Northeast, stating its intention to allow only four RTOs in the United States, plus ERCOT. 6-19

79 procedural problems and the absence of any showing that the benefits available from the FERC's policies outweigh the resulting costs. The Commission asked the FERC to address the major issues that had been raised, including (1) the FERC's failure to directly and openly address, through a factual inquiry, the threshold question of whether end users within the scope of any proposed RTO would be better off as a result of the change in the status quo, and (2) its failure to consider the limitations on its authority when a specific RTO is to be designed and implemented. (b) The Alliance RTO NC Power proposed to join the Alliance RTO (ARTO), which included the transmission systems of a number of utilities from Virginia to Michigan and from other parts of the Midwest, including AEP, Consumers Energy, and FirstEnergy. After issuing several orders that ultimately approved ARTO as an RTO, the FERC last December rejected it in favor of the Midwest ISO (MISO). The members of ARTO were required to file a statement of their plans to join a different RTO. NC Power has recently indicated its intention to join PJM, as PJM South. 3. INTERCONNECTION NOTICE OF PROPOSED RULEMAKING The FERC issued an advanced notice of proposed rulemaking on October 25, 2001, with respect to adopting a standard Generator Interconnection Agreement and standard Interconnection Procedures. A Notice of Proposed Rulemaking (NOPR) was issued on April 24, 2002, proposing a standard agreement and standard procedures that would become part of each transmission provider's OATT. The FERC requested comments on a number of issues, including whether its current pricing policy should be retained. The Commission intervened in this NOPR on June 22, 2002, and filed comments on several issues. The pricing issue is of particular importance to a consideration of infrastructure issues and is the only issue that will be addressed in this report. The FERC has proposed to socialize the costs of transmission upgrades caused by the interconnection of new generators, by spreading them out over all users of the 6-20

80 transmission system or RTO. Many states with bundled retail service believe this socialization will unduly burden retail ratepayers, who will gain relatively little benefit compared to the costs they will be required to bear. The National Association of Regulatory Utility Commissioners (NARUC) and SEARUC have passed resolutions urging the FERC to recognize its own statement in Order No with respect to the economic inefficiency of averaging, or socializing, costs and thereby distorting consumption, production and investment decisions. Both groups urged the FERC to use a pricing policy that required expansion and upgrade costs to be borne by the transmission customers who benefit from the expansion and/or upgrades. The Commission's comments were consistent with these resolutions. Resolution of the expansion and upgrade costs allocation issues is critical to any significant expansion of the transmission grid and could have a very significant effect on both the nature, timing and costs of future upgrades. The FERC's ultimate determination of pricing policy, and the extent to which States are ultimately found to be preempted from allocating those costs away from retail ratepayers, when appropriate, will determine the effects the proposed merchant plants in North Carolina and elsewhere will have on the reliability of service, if expansions and upgrades are not undertaken, and on the cost of service if they are. 4. STANDARD MARKET DESIGN NOPR On March 15, 2002, the FERC issued a Working Paper on Standardized Transmission Service and Wholesale Market Design, requiring that comments be filed March 27, (This was subsequently extended to April 10, 2002, one day after comments on the FERC's cost/benefit study were due.) This was followed by an Options Paper, issued April 10, 2002, which identified options for the FERC to pursue in resolving a number of the issues recognized in the Working Paper as needing further discussion. The comments on both the Working Paper and the Options Paper will be used by the FERC to develop a NOPR to be issued this summer. The Commission filed comments on both papers. 6-21

81 The FERC's stated purpose in issuing the Working Paper is to build upon its Order No. 888 and Order No by replacing the pro forma open access tariff approved in Order No. 888, which was limited to wholesale transmission, with a new tariff designed to impose a standard market design (SMD) on all public utilities owning, operating, or controlling interstate transmission facilities. According to the proposal set out in the Working Paper, a new transmission service, to be known as "Network Access Service," would be established. All transmission service, including that provided as part of bundled retail service by vertically integrated utilities, would be placed under the new tariff. This new tariff, among other things, would require that an independent entity administer the imbalance and transmission markets for its regions, implement the standard market design, and use Location Marginal Pricing (LMP) to manage congestion. The independent entity also would be required to assure that purchases and sales of energy and operating schedules were coordinated with transmission schedules. Finally, transmission owners that are not part of an RTO would be required to contract with an independent entity to determine transmission capability on a regional basis and to participate in regional longterm planning and expansion, and each transmission owner would have to offer either a centralized market or a physical hub within its system. The Commission filed comments on both of these FERC issuances. Its response to the Working Paper objected to the proposed SMD on numerous legal, policy, and factual bases, which are summarized below. 1. The FERC's assumptions with respect to discrimination, transaction curtailments, market design flaws, and benefits to all customers, among others, have not been shown to be valid in North Carolina, specifically, and in the southeast, generally. 2. The process used by the FERC is invalid, in that it purports to rely on a wide consensus obtained through written comments, conferences, and workshops, when inadequate notice and opportunity to comment on all issues was provided, both substantively and procedurally, to the particular prejudice of state commissions. 3. The FERC's attempt to require that all transmission service be subject to the 6-22

82 same FERC-jurisdictional tariff in this proceeding is unlawful, beyond the FERC's statutory authority, and inconsistent with the United States Supreme Court's recent opinion upholding Order No The proposed SMD unlawfully extends the reach of the FERC's jurisdiction beyond the regulation of transmission into areas either outside the FERC's statutory authority, such as the requirement that a transmission provider create a centralized market or physical hub, or specifically reserved to the States, such as the dispatch order of generating plants in retail rate base. The SMD NOPR is expected to be issued within the next week or two. Its potential effects on the ability of North Carolina to control the use of the generation and transmission facilities for which its retail ratepayers have paid and the negative effects that could result cannot be overstated. Because the NOPR has not been issued, much less a rule adopted, however, these effects are necessarily beyond the scope of this report. C. THE CURRENT STATUS OF TRANSMISSION The FERC has become very forthright recently in characterizing its goal as one of nationalizing the transmission systems currently operating in the United States. Historically, the vast majority of electric service has been provided by an integrated electric utility system for its control area, composed of three basic elements: (1) the generation resources, which produce electrical energy; (2) the transmission network, which transports the energy at high voltage from the generating plants to substations in proximity to customers and provides interconnections with other utilities; and (3) the distribution system, which carries the energy from the substations to the ultimate consumers. 12 The system is integrated in that all three elements are connected as a network and operated as a single 12 Some utilities do not own all three elements, particularly public entities. The electric membership cooperatives in North Carolina, for example, own some generation through NCEMC (mainly a share of Duke's Catawba nuclear plant) and each owns its distribution system. They do not own transmission. 6-23

83 system. While a number of states in other parts of the country have required their utilities to separate these three elements to varying extents, retail electric service within SERC is still provided in an integrated fashion by most utilities. Even in the parts of the country that have restructured, there is still a great deal of integration. PJM, for example, still operates transmission and generation as an integrated whole for the most part, with specified rights in the various utilities. (It has operated that way for 50+ years quite separate and apart from the pursuit of competition.) Individual vertically integrated utilities in Pennsylvania, for example, were not required to divest their generation or transmission facilities. Vertically integrated utilities plan their generation and transmission systems on an integrated basis to optimize the location and capacity of generating units to match the configuration of the transmission grid. In addition, they add transmission lines and substations to match the locations and usage of their generating units. This optimization will be impossible to achieve if transmission is unbundled (separated) from generation. In fact, many question whether the two can be separated since a transmission system is operated in large part by adjusting the output of generating units. The FERC's proposed standard market design, which would require generation to operate out of dispatch order (i.e., a more expensive generating plant would be run before a less expensive one), to relieve congestion across multiple control areas, would appear to destroy the benefits integration was designed to achieve. These benefits have been described as follows: Decisions about generating and transmitting power are closely intertwined. The daily operation of the transmission system depends upon where and when to generate power. Longer-run decisions about investing in generation or loads are closely linked to those concerned with expanding the transmission system. The existence of these interrelationships or complementarities between functions presents opportunities to expand both systems more efficiently or at a lower cost when done jointly rather than separately. A fundamental decision with restructuring concerns how to decentralize decisions about generation and loads and still acknowledge the complementarities between generation and transmission Energy Modeling Forum,

84 As this passage reveals, there is no consensus among experts that a national energy marketplace of the type envisioned by the FERC is appropriate. There also is no consensus among policymakers and others that, even if the technical complexities are resolved, the benefits to be derived from such dramatic changes could possibly outweigh the costs. With respect to the effects of the FERC's push to "nationalize" the grid on reliability, NERC has consistently expressed concerns about the new uses to which the grid is being put without appropriate mechanisms being in place to handle the stresses. NERC's list of major outages, beginning with the Northeast black-outs in 1965, shows that such outages have become more common in the last few years (although not in the Southeast). NERC has expressed concerns over RTO developments because new systems and organizational structures would have to be implemented over very aggressive time frames, noting that the scale of the responsibilities that would be transferred to these new organizations is unparalleled in the history of the industry. 14 According to the United States Department of Energy's (DOE) "National Transmission Grid Study," the highest levels of congestion are found along transmission corridors from (1) Minnesota to Wisconsin, (2) the Midwest into the Mid-Atlantic, (3) the Mid-Atlantic into New York, and (4) the Southeast into Florida. Interestingly, DOE also found congestion in some areas where there have been few Transmission Load Reliefs (TLRs) called, such as in the Southeast. DOE's analysis suggests that substantial congestion would result in these areas, if there were greater volumes of wholesale electricity transactions. 15 In particular, all of the transmission paths out of TVA would be congested at some point. DOE characterized trading into the Southeast as difficult because TVA controls the majority of transmission access into and out of the region because of its location NERC's Reliability Assessment (October 2001), p. 23. DOE's "National Transmission Grid Study," May 2002, p. 12. Id., at p

85 DOE's study discusses the results of a recent FERC analysis of transmission constraints in the United States, which was presented on December 19, The FERC's Staff identified 16 constraints characterized by a large number of TLRs events or high price differentials across an interface. The FERC's map showing these constraints is set out below: 17 As can be seen from the map, none of these constraints are in the Southeast. 17 FERC, 2001, "Electric Transmission Constraint Study," Division of Market Development. It can be downloaded from http.// 6-26

86 According to NERC's Reliability Assessment, some important lessons have been learned about the impacts of competitive markets upon reliability. Of importance to this report are the following: markets for ancillary services have proven difficult to develop, particularly with respect to reactive power, which cannot be transported easily on the transmission system; coordinating markets for balancing energy, capacity, and regulation has proven to be a difficult task; the separation of generation and transmission, where it has occurred, has resulted in sub-optimal transmission system planning in some areas; generation is not locating close to demand centers; and loading will continue to increase on existing transmission systems. 18 The section of a recent NERC report that discusses transmission expansion issues and makes recommendations is included at the end of this chapter as Attachment VI-B. The SERC section of NERC's Reliability Assessment indicates that heavy north-tosouth transfers into the SERC Region over the last two summers have caused significant voltage depression and concerns that voltage stability limits may be exceeded. Recent studies have determined the maximum simultaneous north-to-south transfer that can be supported while ensuring system reliability. Results of those studies will be used by system operators and security coordinators to monitor system conditions to ensure that maximum transfer limits are not exceeded. The areas of concern, including other parts of the country, are shown by arrows on the map on the following page. 18 NERC's Reliability Assessment (October 2001), p

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88 The SERC section of NERC's Reliability Assessment also indicates that a large number of new generators have applied for interconnection in the Southern subregion. Interconnection studies have shown major stability problems, which result in large portions of the system pulling out of synchronism. Major transmission system improvements will be needed to solve these stability problems. These are the kinds of improvements that NARUC and SEARUC believe should be paid for by the generators or those who purchase from them, rather than those costs being disproportionately assigned to Southern's retail ratepayers, who may not even be served by those plants. The Southeastern Infrastructure Assessment indicates that the north-to-south flows from the summers of 1999 and 2000 were reversed in the summer of 2001, with transfers flowing south-to-north. The VACAR section of this report indicates that transmission assessment studies and recent operating experience indicate that the limitations on the interfaces between VACAR and other subregions and Regions tend to occur on facilities outside of VACAR. According to SERC's 2002 Summer Assessment, the transmission systems within SERC can be expected to provide adequate and reliable service over a range of operating conditions this summer. Numerous re-conductoring and line upgrades have been completed since last summer and several lower voltage lines that are limits to transfer are in the process of being upgraded. D. ACTIVITY BEFORE THE COMMISSION In response to the utilities' 1999 Integrated Resource Planning (IRP) filings, in Docket No. E-100, Sub 84, the Public Staff expressed concerns about the lack of technical details for assessing the impact of various planning elements on reliability. The Public Staff requested that the Commission require the utilities to provide information about direct utility interconnections/transfer points, including voltage levels, transfer capabilities, limitations on planning from transfer capabilities, and plans to improve or limit these transfer capabilities; a descriptive and narrative discussion of the impact of the FERC's open access policy on 6-29

89 transmission line capabilities and planning; the need for building or upgrading lines to meet native load growth; plans to meet expected wheeling demands; and a list of all transmission lines (161 kv and above) that were operated above 80 percent of design limits, plus certain information about any of these lines. Duke objected to this request for information because of the amount of the data and the fact that it would be available in the form of reports and models already produced. Duke recommended that the parties meet to discuss the Commission's needs and develop an efficient and responsive reporting requirement. The Commission adopted Duke's suggestions that the parties try to work out an acceptable reporting mechanism. The Commission also concluded that future filings by the utilities should continue to include a discussion of the adequacy of their respective transmission systems. After several rounds of discussions, the parties settled on a mechanism, which was used for the utilities' filings this past September. The utilities agreed to include in their annual report filings, in addition to the data required by Commission Rule R8-60, a copy of the most recent completed FERC Form 715, including all of its attachments and exhibits. In addition, the utilities agreed to meet with the Public Staff, within 30 days of the filing date of the annual report, to discuss detailed information concerning (1) their transmission line inter-tie capabilities; (2) their transmission line loading constraints; and (3) planned new construction and upgrades within their respective control areas for the planning period under consideration. The Commission accepted this agreed upon mechanism in its Order dated March 28, 2002, in Docket No. E-100, Sub 93, approving the utilities' IRP filings. Because of the FERC's determination to pursue wholesale competition and exert more control over the utilities' transmission systems, the Commission initiated a new docket, Docket No. E-100, Sub 94, by Order dated September 6, 2001, to become better informed about the status of the electric transmission facilities used to serve North Carolina retail customers and the extent to which transmission-related issues are likely to arise in the future. To that end, the Commission Order required Duke, CP&L, and NC Power to file comments providing specific information in response to the following matters: 6-30

90 1. Where existing transmission facilities are located, who owns them, their capacity and peak demand, and what capacity constraints, if any, currently limit the ability of North Carolina utilities to move power into and through their systems for the purpose of serving retail and wholesale customers throughout North Carolina; 2. The exact manner in which the existing transmission grid is operated, how much wholesale load moves through the existing transmission grid, and whether competitive power providers believe that their ability to deliver power for use in North Carolina is hampered by either the physical condition of the existing grid or the manner in which the existing grid is operated; 3. The transmission planning process, such as: a. how expansion decisions are made, b. what criteria are used to make such decisions, and c. what transmission expansions are currently either underway or under consideration; and 4. How to deal with transmission-related problems which have already arisen or may arise in other states, such as: a. how North Carolina should avoid the development of transmission constraints such as those which contributed to the recent problems in California, b. how North Carolina can avoid having retail ratepayers put at risk of paying for facilities constructed to move power from out-of-state generators who want to move power through North Carolina for sale in non-north Carolina markets, and c. how North Carolina utilities determine whether it is more efficient to add additional transmission capacity in lieu of constructing new generation or vice versa. The utilities filed several hundred pages of initial comments and exhibits in response to the Commission's Order. Reply comments were filed by the Public Staff, the Attorney General, Fayetteville Public Works Commission, and the Carolina Industrial Groups for Fair Utility Rates (CIGFUR). In its reply comments, the Public Staff stated that it believed the comments filed by the utilities provided useful information and were a good beginning, but because of the complexity of transmission-related issues, the Public Staff recommended that the 6-31

91 Commission consider asking additional questions, requiring oral presentations and opportunities for questions and discussions, and taking other steps to obtain additional information. The Public Staff recommended that the Commission consider requiring each utility to make additional filings and to make individual oral presentations with an opportunity for questions and further discussion being provided. It stated that the Commission also may want to consider less formal means of obtaining information, such as workshops and site visits, as necessary. On June 11, 2002, the Commission issued an 18-page order summarizing the initial comments and reply comments and concluding that CP&L, Duke, and NC Power had provided the Commission with significant background material related to their individual transmission system operations. The Commission noted that further relevant transmissionrelated issues may be specifically addressed in other dockets. The Commission, therefore, concluded that it should hold this docket in abeyance pending further order to allow the Commission to request any additional general information that it may need in the future. E. CONCLUSIONS The Public Staff was requested to quantify and identify constraints and then to draw conclusions about whether the potential for the development of generation capacity is limited in North Carolina because of transmission constraints. The Public Staff has examined a large amount of information over the last several years concerning transmission operations and planning, in an effort to develop the reporting mechanism discussed in the preceding section. The Public Staff's review of this information revealed that overall North Carolina's transmission systems currently are in very good shape. Because it is uncertain how many and which of the proposed merchant plants will be built and to whom they will sell (i.e., within the control area versus outside of it), it is impossible to quantify the exact effects that they may have. This uncertainty is exacerbated by the fact that so many merchant plants also have been proposed in Virginia and South Carolina. Because (1) a company building a generating plant has to commit to construction before an expansion of the transmission system is undertaken, and (2) transmission 6-32

92 construction/upgrades often take longer to construct than generation, there could be a short-term imbalance that affects the ability of new generators to operate in North Carolina and a need for special mechanisms to prevent them from negatively affecting retail service when they do operate. Because bundled retail transmission service currently is under the jurisdiction of the Commission and the FERC's currently approved open access tariffs recognize bundled retail customers' existing rights to their transmission systems, any shortterm problems should not affect the quality or price of retail service. Of more concern are the potential effects on the transmission systems of the North Carolina utilities from the exporting of large quantities of merchant power at a time that parallel path flows and congestion are an increasing problem because of merchant activities around the country and the broader concerns raised by the FERC's Interconnection NOPR and its pricing policies and by its SMD proposal. Unquestionably, if constructed, merchant plants (or those buying from them) will be using transmission capacity that currently exists as a reserve for retail native load customers and historically served wholesale customers within the North Carolina utilities' control areas. This use of reserves could increase the North Carolina utilities costs of service. Because of the number of proposed merchants in the Rowan County area, for example, Duke's proposed Buck County plant may very well end up having to pay substantially for upgrades, under the FERC's current and preferred pricing policy, that it would not have had to pay but for the existence of the merchant plants. Other than in that area, any upgrades that could be required should not overly burden ratepayers in the shortterm. Burdens on retail ratepayers could result, however, when the current transmission reserves for growth and contingencies reach the point that substantial upgrades would be required. It is very difficult to comprehensively address the potential effects of merchant plants on reliability and/or cost of service because transmission policy is in such a state of flux at this time. To the Public Staff's knowledge, there is no currently implemented approach or procedure in place in any state for measuring the adequacy of transmission for future utilityowned plants in light of the advent of merchant plants and power trading. Developing such 6-33

93 an approach or procedure would be a daunting task at best because of the nature of transmission and the difficulty of predicting the precise effects of a multitude of possible events and load patterns, among other things. In addition, given the recent downgrading of the debt ratings of so many of the merchant plant developers and power traders, it is less than certain at this time that merchant plants in large numbers will ever be developed. The effects of merchant generation on transmission may ultimately prove to be the most negative of the infrastructure issues discussed in this report. However, because of the nature of electric transmission, this area is the most difficult to analyze, much less to identify and quantify constraints. The Public Staff, therefore, recommends that the Commission make every effort to continue obtaining additional information and to remain actively involved at the FERC, and in the federal appeals courts to the extent necessary. Additional efforts should be undertaken to better educate the Commissioners, Commission Staff, Public Staff and other interested parties. Receiving regular updates from the utilities on the results of studies, particularly the interconnection studies for merchants, might be advisable, as well as the scheduling of regular presentations, such as those requested last year. An issue worthy of further consideration in this regard might be the legality and appropriateness of conditioning future merchant certificates upon an appropriate allocation of costs for transmission upgrades to their proposed plants. Another solution to consider might be to require that merchants sell at least part of their output to one or more customers within the control area in which they propose to locate, which is a requirement South Carolina and several other southeastern states appear to be considering. Further pursuit of additional information in this docket, in the annual IRP dockets, and otherwise would be advisable, with the information produced in a format that is as accessible as possible. As additional information becomes available about the potential negative effects of merchants on North Carolina's transmission system, the Commission will need to be prepared to take timely action as appropriate to address these potential effects. 6-34

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