PAGE 1
ELECTRIC POWER WHEELING AND DEALING: Technological Considerations for Increasing Competition VOLUME II -CONTRACTOR DOCUMENTS Part C 1. Competition and The Role of The Capital Markets in Restructuring The Electric Power Industry 2. The Siting of EHV Electric Transmission Lines 3. Environmental Effects of Increased Competition in the Electric Power Industry 4. Economic and Planning Implications of the FERC Notice of Proposed Rulemakings on Independent Power Producers: A Review of Documentation The Contractor Documents were prepared by outside contractors as an input to an OTA assessment. They do not necessarily reflect the analytical findings of OTA, the Advisory Panel, or the Technology Assessment Board.
PAGE 2
OTA DRAFT WORKING PAPER COMPETITION AND THE ROLE OF THE CAPITAL MARKETS IN RESTRUCTURING THE ELECTRIC POWER INDUSTRY JANUARY 1988 Prepared for the Office of Technology Assessment by Scott Fenn Investor Responsibility Research Center This is a DRAFT OTA Working Paper. It is being circulated for review only and should not be quoted, reproduced, or distributed. The conclusions expressed in this report are those of the authors and do not necessarily represent the views of OT A. This report has not been reviewed or approved by the Technology Assessment Board. ~--r
PAGE 3
CccPftITIOB AllD TBB ROLB or TD CAPITAL MUDTS I USTROC'.rURIRG TIIB BLBCTRIC POIIBR IIIDUSTRY Prepared for the Office of Technology Assessment By Scott Fenn Investor Responsibility Research Center Contract Number R3-6590.0 January 1988
PAGE 4
COiriDTS Introduction ......................................................... Chapter I -Capital Investment in the Electric Power Industry Capital spending in the electric power sector Ezternal capital needs ........................................... Other recent trends in electric power financing Chapter II -Financial Restructuring in the Electric Power Industry Increased competition: the dominant force behind restructuring Other forces promoting utility restructuring Types of utility restructuring activity Chapter III -Investment Community Views on Utility Restructuring Appendiz A -List of persons interviewed Appendix B A glossary of investment terms Footnotes ........................................................... 1 2 2 3 8 14 14 21 26 46 55 56 57
PAGE 5
Introduction The purpose of this paper is to provide the Office of Technology Assessment with an overview of some of the investment issues affecting the future of the electric power industry in support of OTA's ongoing study on competition in the industry. The paper will focus on how proposed changes in the regulation and structural organization of the industry might influence the perceptions of institutional investors and their willingness to provide capital to the industry. The paper is organized into three chapters: Chapter I provides a description of current investment issues and financial trends in the industry. Chapter II discusses the emergence of financial restructuring activity as a major factor in the industry. Chapter III presents the views of the investment community regarding regulatory and financial restructuring, the appropriate government role in regulatory reform and how proposed regulatory changes might affect the willingness of investors to provide capital to the industry. The materials presented in this paper are from a variety of sources, including personal and telephone inter~iews with representatives of the investment community, relevant reports and articles that have appeared in the daily and trade press, materials presented at conferences, and published research by the author, especially the IRRC reports Mergers and Financial Restructuring in the Electric Power Industry and Institutional Investment in Renewable Energy Technologies. 1 A list of persons interviewed specifically for this report is attached in Appendix A. Acknowledgements of other persons whose views or comments are reflected in this report are found in the footnotes and in the two reports mentioned above. \
PAGE 6
Chapter Xa Capital Investment in the Electric Power Industry The electric power sector is one the nation's most capital intensive industries, and financing the generation, transmission and distribution assets of the industry has historically been a major factor in U.S. capital markets. As of 1980, investor-owned electric utilities had invested an average of $3.07 in plant and equipment to support each $1 in annual revenue from electricity sale. In contrast, General Motors had a fixed asset investment of 16 cents per dollar of sales revenue in 1980 and Exxon had fixed asset investments of 31 cents per dollar of sales revenue. 2 Capital spending by the electric power industry (in nominal dollars) increased from SJ billion in 1948 to more than $20 billion in 1974 to a peak of about $40 billion in 1982. Much of this expansion was financed externally through the debt and equity markets. In recent years, capital spending in the electric power industry has begun to decline substantially, although some industry forecasts expect such spending to begin to climb sharply again by the mid-1990s as the industry enters its nezt building cycle. 3 Meanwhile, a variety of new trends have emerged in the ways the remainder of the industry's capital needs are financed. This chapter will examine how much capital is provided to the electric power sector, in what form, by whom and under what assumptions. C&ital 1m,Qding in the electric power sector: Recent trends in capital spending by the electric utility sector--as well as one forecast of future capital needs--are shown in Table 1. As can be readily seen, capital spending in the electric power sector is falling rapidly (in real terms), principally as a result of a dramatic falloff in spending by utilities for new generating 2
PAGE 7
Table 1 Total Capital Expenditures in the Electric Utility Industry (in 1987 dollars) Gefterallan TraMnllSSICMI Dtstnbullon M.lc1 .. n10 Toeat 1976 JO~ 5.424 8.:B> 1.997 .16.409 1977 3.3.246 s.a 1.an 1 720 J.8.;,.51 1978 35.853 4.471 7.099 1.988 49.411 1979 37.242 5.06.S 7.979 1.996 52.282 198) 35,179 4.484 7.226 2215 49.104 1981 37.540 3.845 8212 1.988 51.585 1982 38.529 4217 7.n.37 1,995 52.378 11983 35.793 4,103 8.025 2.247 50.168 1984 31.081 3.937 7,895 2.726 45.639 f :: 27.410 3.928 8.091 1.579 41.~ 7.1.350 3.767 8.294 1,336 34.747 foNcasl 1987 15.5.ll 3,500 8.~ 1. 117 29.052 1988 11,950 3,150 8. 11B) 8.~ 2.645 .... 7,482 749 19.466 1991 7,'SJ 2.040 8.425 738 19.193 1992 6.950 1,875 a.a 701 18.222' : 1993 9,(8) 2.100 8,841 fill 20,822 1994 12.0l 2.~ 9,002 9n 25.399 1995 14,870 3.ax> 8,947 1, 27,050 4.250 9,718 1,641 42.657: I S211[~1: llactd~Al Wgrl~, Annual Industry Forecast, September 1987 capacity. Total capital spending in the electric utility industry has already fallen about by about one-third in real terms since it peaked in 1982, and is expected to decline considerably further before it begins to rise again in the early 1990s. Ezternal capital needs: In the short term, the decline in overall capital spending in the industry is particularly significant because it is occurring at a time when the power industry's incernal cash generation capability is climbing--me~ning that less and less of the industry1s capital spending needs 3
PAGE 8
' Figure 1 Blectric Utility Construction Bzpenditurea, 1980-898 (Billions of Dollars) 30 )Ot 21 S 21 J 21 0 27 0 2S. \910 1981 1182 1983 1984 198~ 1988 1987! ll88E l989E E Esumate Source: Salomon Brothers Stock Research, "Quarterly Review of Electric Utility Quality Measurements," Oct. 12, 1987. to be financed externally. As shown in Figure 1, Salomon Brothers Inc. predicts that the utility industry will finance 84 percent of its construction expenditures from internal funds in 1988, and 88 percent in 1989--up from only about 33 percent in 1980. In addition, Salomon Brothers estimates that by 1989, 60 percent of the electric utilities it follows will be generating all of the capital they need for construction from internal funds. These overall figures suggest that capital availability--at least in terms of the total amounts of funds needed in the electric utility sector--is not a major problem in the electric utility sector in the near term from an industry-wide perspectiye. (This point is discussed further in Chapter III.) Rather, the capital availability problems in the industry appear to relate to certain subgroups of the industry and to perceptions of potential future problems: 4
PAGE 9
Pipopsiolly xeok utilitias--Some utilities, such as Public Service Co. of New Hampshire and Long Island Lighting Co., are in such poor financial shape that they no longer have access to the capital markets to complete ongoing construction projects. Other utilities that have major construction proiects--especially nuclear plants--undervay are being forced to pay a premium for capital because of investors' perceptions that there are considerable risks associated with these projects. Neat pop-utility deyelopers--Many of the new non-utility power developers (both QFs and IPPs) entering the industry do not have much cash generation and also do not have the track record or the balance sheet needed to gain access to private capital markets. Those that do have to pay a risk premium because they operate in the riskiest portion of the electric power field--generation--and do not have stable earnings from a regulated monopoly franchise to .offset these risks. Expectations of future capital needs--Some utilities, non-utility power producers and public policymakers question whether sufficient capital will be available to the electric power industry to meet ezpected future electricity demand growth, particularly starting in the mid-1990s. While the existing capital needs of electric utilities are being met largely through internally generated funds, the potential for future capital availability problems suggests that the means by which the industry meets its needs for external capital remains important. Historically, the external capital needs of the electric power sector have been met with three types of long-term financing: 5
PAGE 10
Congnon stock--the equity in the company issued to individual and institutional shareholders. Preferred stock--typically fised rate securities that pay dividends whose rights are superior to those of common stockholders but junior to those of debtholders. Long-term dabt--typically in the fom of 10 to 30 year fixed rate mortgage bonds sold to individuals and institutions. As shown in Table 2, the percentage of these types of capital that, along with short-term borrowings, comprise the electric utility industry's capitalization has remained relatively steady over the past 20 years, although there has been a noticeable increase in the common equity component in recent years as a consequence of the industry's improved internal cash generation. Table 2 Capitalisation Ratio of Blectrlc Utility Industry (1965-1987) (6/30) C41Pita1i1ation, llH ll1..Q llll ll.U ll.15 lll1 Common Equity 38.3 34.1 34.3 36.5 40.5 41.3 Preferred and Preference Stock 9.3 9.5 12.1 11.7 9.8 8.3 Long-term Debt 50.6 53.0 so.a 48.6 48.4 48.1 Short-term Debt 1.8 3.4 2.9 3.2 1.4 2.3 Sources: Leonard Hyman, America's Electric Utilities: Past, Present and Future (Public Utilities Reports, Arlington, Va., 1983); and Salomon Brothers Stock Research, "Quarterly Review," Oct. 12, 1987. 6
PAGE 11
More detailed information on the types of financing and the purpose of these financings is shown below in Table 3. As can be seen, total financings by the investor-owned utilities during the first rine months of 1987 amounted to $16.8 billion, with $10.4 billion of this representing new cash raised and the remainder being refinancings. Table 3 Securities Offerings by Investor-owned Electric Utilities (Thousands of Dollars) .,_ 1---30.1117 .-1-s.30, 1-T ... a.en: T__, Elec:tlic Long-term debt 14,(m,29'l 10,94.5.687 26$1650 16.~1.150 Prefened stcx:k 2.389.125 1.958.(D) 1,183,(D) 1,183,00) Conman stcx:k 342,800 245.750 762.tm 531.945 Talal ....... 11.131.307 13,141.437 21531345 17,711.095 s.gi._..,., of flnalcinl .,, type "' .... P\Jclic Long-term debt 11.93),821 10. 111,416 25.729.660 15,g,650 Prefened st0d{ 2.329.125 1,958,(D) 1,183.CD> 1, 183,00) Conmen stock 342.800 245.750 762.tm 531.945 Total put>uc 14,592836 12.315, 166 27,675.345 17,324,595 Pnvate Long-term debt 2.178,471 834271 864,00) 441,500 PreferTed stock 8),00) btal pnvate 2.238.471 834271 864.cm 441,500 T.-lllwleing 11.131.317 13,141.437 21,531,,MI 17,711.095 .... 1 of ....... bf purpoN of .... New money Long-tam debt 8.615.978 aarz.cm 102IB.838 7,423,838 Preferred stock 1,481,125 1,3l5,(XX) 835.CD> e.cm Conmon stock 328.800 245,75) 498,195 lotat new money 10,425,993 7,542.782 11,8S3.783 8,763,003 Refu-dng Long-term debt 5,483,314 4,853,655 16,313,812 8,621,312 Preferred stock D.cm 75.1,(XX) 348.(D) 348,00l Conmon stock 14,(D) 33.750 33.750 i>tal reflr,di,g 6,405.314 S.fD;.655 16,685.562 9,003,002 TOIIII~ 1U31,307 13,141,437 21,531.MS 17,791,095 SegNpdon ol ~.,, ....... ol .... Con1)81JM Long-tenn debt 3.333.SOO 3,033.500 7.3)3.(D) 4,413,00) Prefened stock s10.cm 510,(XX) 265,(D) 265,00) Camion Sb::k 36.625 36.625 216,964 165,245 Tota~ 3.IB>.125 3,511),125 7,684.964 4,&a245 Negotiated Long-te,m debt 8.587,321 7,Qn,916 18.526.650 11,196,650 Prefem,d stock 1,819,125 1,448,(XX) 918,(D) 91a.cm Comnon~ :DS.265 D,125 545.731 366,700 Total negotiated 10,712.711 8.T.35.041 19,fS).381 12.481,350 Priwle s8'es 2.238.471 834271 864,(D) 441,500 TOIIII,._.... 11.131,307 13,141,437 21.531,345 17,7N,095 S2Ym: Ebasco Business Consulting as reprinted in Electrical World. November 1987. 7
PAGE 12
Other recent trends in electric power industry financing: In recent years, a number of new trends have begun to emerge in the financing of electric power facilities. Among the most significant of these trends may be the entry of non-utility entities into the power generation market, the emergence of innovative financing techniques as a major source of funding for new electric generating facilities, and the growing level of ownership of electric utility common equity by institutional investors. kew entrants into power generation sector--One of the most important new trends in the financing of the electric power industry is the fact that regulated utilities are no longer the only entities in need of capital. In the wake of the Public Utility Regulatory Policies Act of 1978, a whole new industry of non-utility entities has entered the generation side of the business. After an initial lag time of several years, growth of this non-utility side of the electric power industry has been quite rapid, as has been documented by a number of recent studies. 4 The emergence of these new players has been important from a financing standpoint for several reasons. First, many of the companies that entered this field were start-up ventures, with financing needs that were very different from the traditional asset-based financing used by regulated utilities. As a consequence, these new companies havE tended to utilize various types of innovative financing techniques to raise capital. Some of these financing methods--such as the use of leveraged project financing--have proven so successful that they are now being imitated by the rest of the industry--including some regulated utilities. Second, as these non-utility companies have matured, they have begun to undertake sizable projects, such that the overall capital needs of these non-utility entities are a growing portion of the total financing being done in the power sector. 8
PAGE 13
Both of these points are illustrated in some recent data gathered by the National Association of Energy Service Companies (NAESCo). Sinc9 1986, NAESCo has been monitoring "tombstone" advertisements run in the Wall Street Journal related to non-utility financings of power generation facilities. While NAESCo's figures for these financings should not be considered a definitive representation of the size of this market, they do tend to indicate that non-utility financings are dominated by project financings and that the overall level of these financings is now a significant portion--perhaps approaching 20 percent--of the total market for external capital in the electric power industry. 5 The relative dearth of new construction by utilities in recent years is, of course, a contributing factor in this rising percentage of non-utility financings. Table 4 BOB-tJTILiff BLBCRIC POWBR PIBAIICIBGS ADVBlr.rISBD IB WALL STRBBT JOURRAL ll.11 ( g mo ) Total$ Value # Transactions Project Financings Cogeneration Resource Recovery Small hydro Wood/peat-fueled Geothermal Wind Total $2,688 million 51 $971.4 million 517.6 290.6 252.0 145.5 68.7 $2,245.8 conventional Financings Total $442.0 $4,426 million 67 $2,453.3 million 773.3 231.5 134.4 110.0 0 $3,702.5 $723.6 Source: National Association of Energy Service Companies, various press releases 9
PAGE 14
Growing use of innoyatiye financing--As mentioned in the previous section, one of the more important effects from the influx of non-utility companies into the power industry has been the use of innovative financing methods. Basically, these companies have had to rely on non-conventional financing techniques in order to attract capital. This has been done in two ways. First, many companies have utilized project financing--where the viability of the financing depends on the project itself and the contractual arrangements between various proj~ct participants, rather than on the creditworthiness of the developer. The financing is typically non-recourse to the developer and is secured by the revenues of the project. Second, independent power developers have been able to take advantage of a number of new financing vehicles that have been developed in American capital markets in recent years, including new leasing arrangements, high yield or "junk" bonds, and master limited partnerships. 6 These financing techniques have not only allowed the independent power sector to become a viable industry, but--as discussed further in Chapter II--are also beginning to influence how some regulated utilities look at their financing opportunities. New trends in utility and IPP shareownership--In addition to these changes in the types of financing being provided to the electric power industry, there have been changes in recent years in who is providing capital to the industry, including a trend toward higher levels of institutional ownership of electric utility common stock. Electric-utilities were perhaps one of the last major industries where thousands of small investors that owned a few hundred shares were the dominant stockholders. Now that is changing, as institutional investors begin to play a more dominant role in trading in electric utility stocks. As Table 5 shows, the overall level of institutional ownership of utility shares rose from 19 percent in 1980 to 30 per~ent in 1985. 10
PAGE 15
Table 5 IOI: 1980 1981 1982 1983 1984 1985 Level of Electric Utility Shareownership by Institutions (1980-1985) Electric Utilities All Cognon stocks 19 35 21 35 24 35 23 35 28 36 30 39 Source: Daniel Burkhardt et al., Public Utilities Fortnightly. May 15, 1986. The level of institutional ownership of utility shares seems likely to continue to rise. Aside from ren3wed institutional interest in electric utilities based on future earnings prospects, institutional investors have developed sophisticated trading strategies for utility shares that are designed to capture--or, in the case of Japanese investors, to avoid for tu reasons--their high dividend payments. The growing popularity of this uae of utility shares as trading vehicles is evident from the eztremely heavy trading volume of some utility shares around the time they near the dates when investors in these shares become entitled to receive their quarterly dividend payments. The higher levels of institutional ownership of utility shares may also contribute to pressures on utility managements to consider mergers or restructuring activities designed to maximize shareholder value. Meanwhile, in the non-utility sector, there is also evidence that institutional investors are beginning to play a bigger role on the equity side of the market. Some institutions appear to see non-utility companies as an excellent way to invest in the possibility of future ev.ergy or electricity shortages, while others are attracted to these companies because of their size 11
PAGE 16
characteristics. 7 The levels of institutional ownership of some of the leading publicly traded non-utility power producers as of Sept. 30, 1987, are shown in Table 6. 12
PAGE 17
Table 6 Il!ISTITO'l'IOBAL CONNOR STOCK BOLDIBGS IR SBLBCTBD ALTDIIM'IVB BIIDGY COMPABIBS Applied Solar Energy Corp. PLM Cos., Class A Chronar Corp. Consolidated Hydro Inc. Energy Conversion Devices Energy Factors Geothermal Resources International Inc. Spire Corp. Catalyst Energy Development Corp. Long Lake Energy Corp. Magma Power Co. Magma Energy Inc. Ultrasystems Thermo Electron Corp. (Sept. 30, 1987) Humber of Institutional Holders 8 g 12 13 12 17 5 10 49 6 31 11 20 59 Common Held by Institutions 8 20 5 36 16 18 9 g 50 7 22 6 32 30 ----Thousand of shares---2nd Quertsr Total Inst. Change in Holdings at Inst. Holdings 2t301a1 _, 15 83 26 -7 -334 22 -19 -1,264 7 332 9 212 155 260 461 489 1,196 811 1,700 436 329 8,365 662 4,534 529 2,541 5,247 Source: CDA Investment Technologies, Spectrum; 13lfl Institutional Stock Holdings Survey. B,ga: This table includes holdings by federal and state chartered banks, insurance companies, investment companies, investment advisers, pension funds, endowments and foundations with equity assets ezceeding $100 million. It does not include holdings by corporations. Corporations hold large positions in several of these companies. 13
PAGE 18
Chapter II: FiDaDcial Jlestructuring in the Electric Power Industry A variety of economic and political forces are pushing the electric utility industry toward an operating environment characterized by more competition and less regulation. Much of the debate over the future of the industry has centered around the issue of regulatory reform. Nevertheless, regardless of what type of regulatory reform eventually does or does not evolve in the industry, a significant amount of financial reorganization and restructuring appears likely to occur. Thia financial reorganization ia likely to take a number of forms--ranging from new financing mechanisms to merger and acquisition activity. In the words of Phillip O'Connor, former Illinois Conanerce Commission chairman and now chairman of Palmer Bellevue Corp., a firm engaged in various utility restructuring proposals, there is "a certain inevitability to (utility) financial and corporate accommodations to change. They are not the causes of the movement of the electric industry into a competitive era," O'Connor notes, "only the mechanisms through which the system will smoothly, or otherwise, adapt 8 Increased Coapetitioaa The Dollinant Poree Behind Restructuring lmm,1atigp pder attask1 In recent years, the rationale for continuing to treat electric utilities as regulated monopolies has come under concerted attack. Part of this attack is grounded in the overall political philosophy of replacing regulation with market forces embodied by the Reagan administration--a philosophy that. has already led to the complete or partial deregulation of most other regulated industries. Aside from a general swinging of the political pendulum toward deregulation, however, a set of underlying 14
PAGE 19
economic, political and technological factors specific to the electric power industry are also undermining the current utility regulatory framework. Among the most significant of these trends are: greater competitio~. among fuels in the energy sector; changes in the power industry's cost struct~re and capacity situation; the consequences of the Public Utility Regulatory Policies Act of 1978; and recent technological developments in the areas of small-scale power generation and energy management techniques. Greatar inter-fuel competitiop--One powerful economic force behind a more competitive utility industry is the worldwide trend toward more market-based pricing of fuels. This competition has been brought on by several factors, the most important of which is the apparent weakening of OPEC in recent years as an effective price-setting cartel. As a result, world crude oil prices have fallen by more than half since they reached their peaks in 1ga1, promoting much greater competition among fuel sources. In addition, oil prices, bing largely market-based, have declined more dramatically than natural gas and coal prices, where prices are largely set through long-term contracts--making oil more competitive with gas and coal in many end-use markets. Another important factor in this increased inter-fuel competition is the stagnation of growth in overall energy demand since the early 1970s. As shown in Table 7, total U.S. energy consumption in 1986 was roughly equal to what it was back in 1973 before the first OPEC oil shock, even though the real gross national product rose 34 percent, or roughly 2.9 percent annually, during this period. Thus, the only source of growth in electricity demand for more than a decade has been increases in electricity's market share relative to other fuels. Electricity has steadily increased its share of the total U.S. energy market from 24.4 percent in 1970 to a record 36 percent in 1986, as can be seen in Table 7. 15
PAGE 20
Table 7 Year 1970 1972 1974 1976 1978 1980 1982 1984 1986 Prillary Energy Consumption by Electric Utilities (1970-1986) Domestic Energy consugtion (ciuads) 66.83 71.63 72.54 74.36 78.09 75.96 70.84 74.06 74.09 Prinlary Energy Inputs at Utilities (quads) 16.29 18.58 20.02 21.57 23.72 24.51 24.26 25.94 26.70 of Domestic Consumption 24.4 25.9 27.6 29.0 30.4 32.3 34.2 35.0 36.0 Source: Derived from Energy Information Administration, MonthJ.y Energy Review, various issues Figure 2 ; CD C 0 e Q. .. 0 0 0 Coat Of Fuels to End Users in ~onstao.t Do11ars (1972 dollars) 15....--------------------------------, 10 ~~~tiol ectrlclty ------: /v""",/'\J ----------------5 Motor Gasoline Residential Heating Oil --___ -----------------------. -: :: ~-.-::-.:: --~ ---~'------------Residential Natural Gos 0-J.--~--------------,---,---,---r---r---,---,---,---,---,--~ 197 3 1974 1975 1976 1977 1978 1979 1980 1981 1982 198 3 1984 1985 1986 1987 Source: Energy Information Administration, Monthly Energy Review, December 1987. 16
PAGE 21
One reason that electricity has been so successful in competing for market share, of course, is that lt is virtually essential for some uses and is the energy source of greatest convenience in many other applications. But for other end-uaea, auch aa reaidential heating and cooling and varioua industrial processes, electricity competes directly with primary fuel sources. In these markets, electricity is essentially a conwnodity that must compete on the basis of price. As shown in Pigure 2, the price gap between electricity and primary fuels has widened considerably since 1980, suggesting that still further gains in market share for electricity are going to be harder for electric utilities to count on during the nezt decade. Changing industry cost structure--Another fundamental factor behind arguments for greater competition in the power industry is the growing acknowledgement that economies of scale in electric power generation no longer ezist for large plants, especially those over 1,000 megawatts. Inflation, lagging technological innovation in large power generating systems and costly safety and environmental regulations have combined to turn what was historically a declining marginal cost industry into an increasing cost one--where each new power plant built results in higher electric rates for consumers. This persistent cost escalation has put severe pressures on the ezisting utility regulatory framework, which was basically designed to function under ezactly the opposite conditions. Regulators, who for many years served primarily to decide how to allocate cost decreases among ratepayers and investors, have learned that allocating large cost increases is consider,ably more problematic. Passing the entire cost burden through to ratepayers, as was generally done throughout the 1970s, proved to be politically explosive and drove large industrial customers to search for alternatives. So 17
PAGE 22
regulators have generally turned in recent years to cost sharing schemes that require investors to share the cost burden caused by the inclusion of ezp6nsive new generating plants in the utility rate base. The results, equally unsatisfactory to many observers, have been a higher cost of capital for utilities and an overwhelming desire on the part of utility managers to avoid new commitments to build new central station power plants. Public Utility Regulatory Policies Act--The Public Utility Regulatory Policies Act of 1978, or PUBPA, provides yet another important stimulus for competition in the industry. The law was designed principally to give a boost to energy conservation and to new sources of electric power generation from such alternative sources as cogeneration, solar, wind and small hydroelectric facilities. Un~ar the act, utilities are required to interconnect with qualifying facilities--purchasing the power these facilities produce at rates equ~l to their own avoided coat--"1d to provide backup power aa neceasary. PURPA and other government incentives to encourage small power production, while creating a nwnber of problems, have worked well from th standpoint of encouraging new sources of supply. In fact, in some ways these incentives have worked better than the authors of PURPA could have anticipated and have served to inject a considerable degree of competition into the generation side of the electric utility business. "PURPA has outgrown the expectations of its creators," notes Martha Besse, chairman of the Federal Energy Regulatory Commission (FERC), and "has grown into a multi-billion-dollar business that is pro~1iding a majority of the new generating capacity in several large regions of the country." 9 Although comprehensive information on non-utility power generation is still unavailable, recent estimates suggest that about 30,000 megawatts of cogeneration and small power facilities will be on-line by 1990, and that the 18
PAGE 23
bulk of this new capacity will be built by aggressive, entrepreneurial companies that operate in a largely deregulated environment. By the year 2000, some estimates suggest that up to 50,000 megawatts of small power will be on-line. 10 "PURPA has changed the rules of the game in the electric utility business," notes Michael Zimmer, president of the Cogeneration Coalition of America Inc., because "electric utilities no longer hold a monopolistic grip on electric generation." 11 Technological adyapcements--Technological advancements involving power generation, transmission and energy efficiency technologies are still another major catalyst for utility deregulation. In the area of power generation, a variety of small-scale, modular generating systems are now available at costs that are competitive with those of large coal or nuclear generating plants. Most prominently, gas-fired cogeneration systems are available from a wide variety of vendors in sizes ranging from 20 kw to 100 MW at costs that make them an attractive alternative to utility bought power for many industrial and connercial power users. To date, most of th cogeneration capacity in operation and under construction is associated with large industrial facilities. However, significant opportunities also appear to be opening up in the commercial sector, where some cogeneration packagers are now installing micro-cogeneration systems (20-100 Jew) in commercial establishments at rates guaranteed to be below the local utility's rate schedule. In addition to cogeneration systems, small hydroelectric, biomass fueled, and geothermal plants are also competitive with utility power in some areas of the country. Meanwhile, the costs of power from other advanced technologies that could be installed in a dispersed mode--including fuel cells, photovoltaics and solar thermal systems--continue to fall. 12 19
PAGE 24
In addition to these advances on the generation side of the electric meter, perhaps even more significant technological developments have occurred in recent years in the area of energy-saving technologies that allow electricity users to reduce their power conswnption. Utilities themselves are becoming relatively active in promoting such demand-side management technologies, with spending by the industry as a whole averaging about $1 billion per year. A 1986 study by the Electric Power Research Institute estimated that utility-sponsored conservation and load management programs could reduce capacity needs by the year 2000 by 80,000 MW below what it otherwise would have been. Similarly, a 1987 IRRC survey of 123 utilities found that 57 utilities that have quantified the impacts of their dem.1Dd-side programs ezpect these programs to hold down future peak demand growth by the equivalent of more than 20,000 MW by 1995--at a fraction of the coat of building that much additional generating capacity. l3 More importantly, an enormous array of energy efficiency measures being implemented outside the scope of utility programs are also ezpected to curb future electricity demand growth. Federal energy efficiency standards for major appliances were enacted in March 1987, for instance, and are projected to save the equivalent of 28,000 MW of power demand by the year 2000. 14 Similarly, recent advances in energy efficient lighting technologies could offer the prospect of a further 30,000 MW savings in electricity usage by the end of the century. 15 Finally, significant advances in technologies will make the opening u.p of the power transmission grid more feasible, resulting in greater wheeling of power between utilities. Perhaps the most important development has been the widespread introduction and diffusion of sophisticated communications and computer control technologies. The development of these technologies has already fostered an increasingly active market in bulk power transfers among 20
PAGE 25
utilities themselves. As these communications-related technologies continue to proliferate and their costs fall, they will increase the technical feasibility of allowing real-time pricing of electricity for retail customers, allowing customers to make electricity consumption decisions based on actual electricity production costs. 16 In addition to advances in computer and control technologies, prospects also appear bright for further breakthroughs in the area of superconducting materials. Although commercial applications for superconducting materials in the power sector are probably at least a decade away, a number of the most obvious implications of superconductors seem likely to increase competition. Superconducting wires, for example, could revolutionize the market for bulk power transfer\, by virtually eliminating transmission line losses. This could improve the conapetitive position of remote generating sources such as Canadian hydroelectric resources, coal-fired or solar generating stations situated in the desert Southwest, or ocean thermal energy facilities located at sea. Likewise, cheap electricity storage devices might greatly expand the range of generating technologies that could be competitive in certain sites. Other Forces Proaotinq Utility Restructuring Increased competition is clearly the dominant overarching trend leading toward a restructuring of the electric power industry. But a number of other factors also deserve attention as potential catalysts for an industry restructuring. In addition to the improved cash generation and financial position described in Chapter I, these factors include what some believe are the inefficiencies of the existing patchwork of utility distribution systems, undervalued utility assets, declining costs, the creation of new financial instruments, and the perception of poor management. 21
PAGE 26
Inffigiangiea of eziatipg electric distribution systu: The existing U.S. electric utility distribution system can perhaps best be described as a patchwork of "artificial" service territories and franchises created largely on the basis of historical accident and political considerations. At present, there are approximately 3,000 entities in the power distribution business, including 207 investor-owned utility operating companies, six federal power marketing authorities, 2,000 other publicly owned systems owned by states, municipalities, or regional governments, and another 900 or so rural electric cooperatives. Many utility experts believe that some consolidation and rationalization of the existing electric distribution systems could yield significant gains in economic efficiency. Although economies of scale in large generating plant construction appear to have largely disappeared, there is some evidence that what have been called "economies of scope," or gains in efficiency resulting from coordination or consolidation of economic activity within a certain geographical area, have reached their limits in the electric utility business. Efficiency gains could result not only from reduced administrative expenses related to consolidating neighboring service areas, but also from reducing the amount of generating capacity reserves, particularly spinning reserves, needed to assure system reliability within a given geographical area. Although some experts believe that much of the potential for economic rationalization pertains to consolidations involving government-owned segments of the industry, even within the 207 remaining investor-owned operating companies--which are an assimilation of nearly 2,000 private companies in existence in the 1920s--there may be further room for gains in efficiency from additional consolidation. Potential efficiency gains have been cited as the principal rationale for several recent mergers between investor-owned 22
PAGE 27
utilities, including the Cleveland Electric/Toledo Edison merger and the proposed mergers of Utah Power & Light Co. with PacifiCorp and Savannah Electric & Power Co. with Southern Co. Underya1uad gaata1 Utilities have another basic attraction from a restructuring standpoint that will become more significant in the contezt of a less regulated operating environment--undervalued assets. The current cost-of-service regulatory system values assets based on the cost of the asset at the time it was built minus depreciation. Under most state regulations, this historical cost-based asset value is kept even if the asset is later sold--preventing the buyer from increasing the book value of the asset to the purchase price and taking depreciation based on the purchase price. Needless to say, this system tends to value assets in a way that deviates greatly from the market-based value of the asset, especially over long periods. Although a number of regulatory proposals for increasing competition in the industry specifically ezclude deregulation of such ezisting "embedded cost" assets, any scenario involving a more competitive industry operating environment and a greater reliance on market-based pricing seems likely to result in at least some added mobility of utility assets. Not all utility assets are undervalued by regulation, of course. Regulation tends to overvalue some utility assets in relation to their market value, particularly new high-cost generating plants. A number of nuclear generating units are now entering service, for ezample, that have installed capacity costs in ezcess of $4,000/kw and will produce power at costs ranging from lSt to 20~ per kilowatt-hour--well in ezcess of the prevailing market price. 17 In spite of such ezamples of overvalued assets, however, cost-of-service regulation tends systematically to undervalue most utility assets relative to their market value because of its emphasis on original 23
PAGE 28
cost. A uwnber of ezan1ples spring to mind: fully depreciated generating plants, the transmission system, real estate and customer energy usage databasas to name a few. The notion of realizing market value for these assets is complicated by the question of ownership of these assets. Regulators may argue that much or all of the difference between book and market value of utility assets is "owned" by utility ratepayers, rather than shareholders--similar to the way they have often viewed ratepayers as having a claim on some of the profits from the non-utility businesses that many utilities have diversified into. Nevertheless, the potential for realizing greater shareholder value from undervalued assets remains one impetus behind financial restructuring in this industry. Palling coats: Falling operating co3ts are another important element of the current business environment that may make utilities more attractive as restructuring candidates. The steep drop in fossil fuel prices in recent years, coupled with the general decline in interest rates, have eased some of the operating cost pressures on the industry. In spite of a flattening trend in utility rate increases, a number of industry observers believe that some of the drop in utility costs stemming from falling fuel prices, tax reform and company belt tightening measures has not yet been fully reflected in utility rates. This is significant because it could help give bidders for a utility, or utilities pursuing recapitalization plans, the leeway they need to offer regulators an important plum for approving these plans--guaranteed rate decreases or a moratorium on future increases. Needless to say, it will be nearly impossible to persuade regulators to approve utility restructurings if the result is a rate increase. Interestingly, a similar regulatory tradeoff involving less regulation in return for a guaranteed moratorium on rate 24
PAGE 29
increases for residential telephone customers was recently implemented by the State of Vermont. 18 This concept has also been contained in several recent restructuring proposals in the electric power industry, including ones proposed by Commonwealth Edison Co. and Public Service Co. of New Mexico. A revolution ip tipancipg: Still another important factor that could play a role in the restructuring of the utility industry is the revolution that has occurred in the financing arena. The emergence of high yield or "junk" bond financing, in particular, gives potential acquirers the ability to raise much larger chunks of money than in the past. Salomon Brothers calculates that the p&rcentage of new issues of corporate debt rated below investment grade rose from 11 percent in 1982 to 24 percent in 1985. 19 Big utilities that might have been "takeover-proof" a few years ago based on size alone are no longer out of reach, as is apparent from the size of some of the oil company takeovers and mergers in recant years. It is also likely that other new financing techniques, such as master limited partnerships for certain bundles of aaseta, may prove useful to utilities, non-utility power developers, or their acquirers as a way of getting market value for undervalued assets. A lingering perc;Gtiop of poor mnnwnont: A final reason why restructuring may be attractive in this industry is the lingering perception that some utilities are poorly managed. Whether accurate or not, many electric utility managers are not well regarded as managers by Wall Street or by the rest of the business community. This view no doubt springs in part froi a decade of newspaper horror stories about nuclear plant cost overruns and accidents. A more fundamental reason for this perception, though, is probably related to regulation, which many managers, including some within the utility industry, believe has served to insulate utility managers from the 25
PAGE 30
types of competitive pressures that businesses operating in an unregulated business environment face. Leonard Hyman, vice president of Merrill Lynch Capital Markets, for instance, contends that if the industry were not regulated, poor management would be a precipitating factor for considerable merger activity. 20 In any case, whether real or not, the perception th~t some utilities are poorly managed cannot help but create the impression among some business managers that they could do a better job of running an electric utility than the ezisting managers. Moreover, some utility managers that J1iwa been successful at coping with the changes in the industry's operating environment also appear eager for an opportunity to rejuvenate some of their less well managed neighbors. Types of Utility Restructuring Activity Several types of financial restructuring are beginning to emerge in the electric utility industry. Most are being proposed in response to general economic trends and by utility managements who foresee a more competitive economic and regulatory environment in the future and believe that new business strategies involving financial restructuring can help their companies prosper. Among the most significant types of financial restructuring evolving are major sale-leaseback transactions, joint venture agreements with non-utility companies, vertical disintegration, leveraged buyouts, negotiated mergers and hostile takeover activity. Sale-1easehack arrangaMnts: One of the most common and least dramatic forms of restructuring that utilities are increasingly considering is the use of sale-leaseback transactions as an alternative to their traditional finance 26
PAGE 31
methods. Utilities have used such transactions in the past for small facilities. Recently, however, they have begun utilizing lease financing in the funding or refunding of major assets. These transactions generally involve utilities selling generating plants or power lines to institutional investors and agreeing to lease back these facilities under a long term contract, typically at very attractive rates relative to existing debt. As shown in Table 9, since the beginning of 1986, 11 power plants, including four nuclear plants, have been sold or put up for sale under sale-leaseback arrangements. The growing use of sale-leaseback transactions may not be terribly important in and of itself. But it is interesting that this financing technique is becoming increasingly popular in the utility Table 9 Major U.S. Electric Utility Sale-leaseback Transactions ...,., ... Notyet~ : ... '~--~~ : : < ::;;_ --. Emnon IBM. Phip Morris Shel Leasing ... : .... ', ........ .,, Bea!rice Fia1ci'1g ServiceS. Ovyslar' FNncial. Dart & Kraft Fnncial,FistOagoleasilg. JC Femey, Saks ., Sellar ... plllll ifflMIINd CerariarE,ag'/Corp .. (Bruce MIi ISfiald,caal BeMr v,,,,,, ~-Tucson Eledric Power Co {Spb.JII wile COIi) Oesnt Gaaation (Borwv.a-C08I) Basin ElectriC Power Co-op (Antelope "*I 2-c:aal) Group of (Owner Trustee, Otio Edisan Fist National Bar* of Bosten) :; (Feny 1-nucmr, ~ Nllccffemg ... Qwysler Rnn:ial. Ford Motcr. Qd.t-Elnestrnent.&4 O,rysler Caplal. Orexel Bumm Leasing, Melon Rnancial ServiceS Orexa Btman Leasi,g, General 8ec1ric Qecit. Shel Leasi'lg General ElectriC Crecit 0glel1arpe Power (Schers 2-caal) Pubic Service of New Mmcico (Palo \farde 1-ru::lear) MantlnlR7Aw (Colsq> 4-coal) Source: Electrical World magazine, September 1987 27 Price $1-blion (appraK) BEST COPY AVAILABLE
PAGE 32
sector largely for reasons other than the traditional advantages to lease financing--n ... ly the transfer of taz benefits. Rather, utilities are viewing lease financing of power plants as a full or partial solution to the "rate shock" problem caused under traditional utility accounting when a major asset enters service. The lease structure allows the rate impact of new powerplants to be stretched out over a longer period of time than is possible with traditional regulatory accounting practices, where the rate impacts are greatest in the first few years of operation. Utilities also see leases as a vehicle for turning physical assets into financial assets and diversifying their asset risks. 21 Finally, lease financing--which has been used extensively for financing non-utility cogeneration and small power projects--also allows the use of greater financial leverage and provides attractive rates, resulting in lower financing costs. Public Service Co. of New Mexico's sale leaseback for $325 million of a portion of its interest in the Palo Verde-1 nuclear unit is expected to .save the utility's customers $375 million through the year 2026. 22 The increasing use of lease financing suggests a growing awareness on the part of utility ezecutives of the need to generate a competitive return on utility assets. Utilities "are not unaware of the risks inherent in failing to generate mazimwn results from the assets on their books," says David Crane, a director of the investment banking firm Babcock & Brown. "Failure to do so may result in unwanted attention from suitors." 23 It is also interesting to note that some of the utilities involved in sale-leaseback transactions, such as Centerior Energy Corp., Tucson Electric Power Co. and Public Service Co. of New Mexico, have also been involved in more extensive financial restructuring measures. Thus, the use of sale-leaseback financing by a utility may be a sign that its management is open to other ideas for restructuring. Joint yant;ura agreements: Another restructuring strategy being adopted by 28
PAGE 33
some utilities that builds on the industry's past ezperience is the use of joint venture agreements with non-utility companies. Utilities have long been involved in joint venture arrangements among themselves to construct major generating facilities and transmission lines. In recent years, however, some utilities have begun pursuing joint ventures with non-utility entities as a way to recapitalise certain assets or to enter new businesses. CMS Inergy Corp. is one of the moat prominent azamplea of a utility that is using the joint venture route to recapitalize major assets. The company struggled for years in a costly and unsuccessful effort to build and license the Midland nuclear plant. Recently, under new management, CMS has formed a joint venture with Dow Chemical Co. and other investors to convert the Midland unit to a gas-fired cogeneration facility and, in October 1987, it announced an agreement to form a joint venture with Bechtel Group Inc. to own and operate the company's Palisades nuclear plant. If approved by regulators, the agreement would mark the first time that the licensee had changed for a U.S. nuclear plant. 24 In a somewhat similar case, Gulf States Utilities is pursuing a joint venture arrangement with three of its large industrial customers that would involve conversion of an ezisting gas-firedgenerating unit into a 200 MW petroleum coke-fired cogeneration facility. The agreement would help the financially strapped utility retain the load of the three industrial customers. 25 Perhaps the best ezamples of utilities using joint ventures to enter new business areas are the joint ventures emerging between utilities and non-utility power producers in the area of cogeneration and small power projects. Utilities are not allowed to own more than 50 percent of the equity in cogeneration and small power facilities thatare classified as "qualifying facilities" under PURPA. Thus, they must find partners in order to participate in specific small power projects. Recently, however, they have 29
PAGE 34
begun to form longer-term partnerships with non-utility firms as a means of increasing their involvement in this field. "I think the more progressive utilities recognize that independent power is here to stay so you might as well be a participant," says Robert Fagan, the new president of a joint venture between Combustion Engineering and a subsidiary of Florida Power & Light Co. 26 In the past two years, at least 10 such joint venture arrangements have been announced, including the following: In late 1985, Southern Electric Investments (a subsidiary of The Southern Co.) entered a joint venture with Chronar Corp. to build a pilot scale photovoltaic cell manufacturing facility and to market PV cells in Southern's four state service territory. In February 1987, Delmarva Capital Technology Co. (a subsidiary of Delmarva Power & Light Co.) formed a joint venture with Conversion Industries Inc. to develop up to nine small power facilities, mostly wood-fired, totaling 148 MW of capacity. In April 1987, FPL Energy Services (a subsidiary of FPL Group Inc., which owns Florida Power & Light) and Combustion Engineering formed a joint venture called Power Ventures to develop and operate cogeneration and small power facilities in Florida and the southeastern United States. In April 1087, Constellation Holdings Inc. (a subsidiary of Baltimore Gas & Electric) and Ultrasystems Inc. formed a joint venture to develop two wood-fired power plants and two coal-fired cogeneration plants in California. Ultrasystems also announced in mid-1987 that it has signed a letter of intent with two utilities to market 20 kW micro-cogen units in their service territories. 30
PAGE 35
In April 1987, Dominion Resources Inc. (the holding company for Virginia Electric and Power) and CSX Transportation Inc. (a subsidiary of CSX Corp.) formed a joint venture called Energy Dominion to develop coaland gas-fired cogeneration projects in New England and the Middle Atlantic states. In September 1987, Atlantic Generation (a subsidiary of Atlantic Inergy, which owns Atlantic City Blectric) and a unit of th privately owned engineering firm Morris lospond Group took on TriStar Ventures (a subsidiary of Columbia Gas Systems Inc.) as a third partner in a joint venture to build cogeneration projects in New Jersey, Ohio and Pennsylvania. The joint venture has siz small plants under construction and 21 in various states of planning--all of wh.ich are gas-fired. In OctQber 1987, Conaunity Inergy Alternatives (a aubaidiary of Public Service Enterprise Group) formed a joint venture with Harbert International to buy GWP Power Systems Co. and Combustion Power Co., two wholly owned subsidiaries of Allied-Signal Inc. that are involved in the development of cogeneration and small power projects. In December 1987, Pacific Gas & Electric announced it was forming a joint venture with Bechtel Power Corp. to pursue non-regulated power generation projects across the country. Utilities are also ezploring the joint venture route as a possible means of financing future central-station capacity. Public Service Co. of New Mezico is a partner in a joint venture that wants to build 2,000 MW of coal-fired capacity on the Navaho Indian Reservation near Farmington, N.M. 31
PAGE 36
Other partners in the project include the Havaho Tribe, Bechtel Corp. and Combustion Engineering Inc~ Construction of the project will not start unless the partners are able to pre-sell at least 1,000 MN of power purchase contracts with utilities in the region. In a similar proposal, Sierra Pacific Resources, the holding company for Sierra Pacific Power, has filed an application with the Securities and Exchange Commission to set up a joint venture for the first 250 MW unit of a planned 2,000 MN coal-fired plant in northeastern Hevada. Sierra Pacific would join with 10 non-utility companies in constructing and financing the S600 million unit of the Thousand Springs project. 27 Vertical, diaip.t;agratiop: Vertical disintegration, or the "unbundling" of utility companies based on the functions that they perform, is another concept that a number of utilities are actively pursuing and several others have under consideration. Basically, this involves the separation of all or portions of a utility' generation, tranamiasion and distribution functions into two or more entities that are owned and operated independently of each other. Utilities are exploring vertical disintegration for several reasons. In one of the moat prominent such proposals to date, Commonwealth Bdison Co. proposed a type of unbundling that appears to be motivated largely by fear of adverse regulatory treatment for ita new power plants entering service. The utility proposed in December 1986 to put three almost completed nuclear power plants in which it has invested $7.1 billion into a separate but wholly owned generating company subsidiary that would sell power back to the utility. During the first five years of operation, the subsidiary would have sold power from the nuclear units for a fee of $600 million plus the units' generating costs. After five years, the utility would be free to spin off the subsidiary. The Commonwealth Edison plan was rejected in July 1987 by the 32
PAGE 37
Illinois Commerce Commission, which chiefly cited the provisions of the plan that would have eliminated prudence audits at the plants. 28 In a more fundamental restructuring proposal, Public Service Co. of New Mezico has proposed a corporate restructuring that would entail the formation of a holding company, the separation of its operations into independent generation and distribution companies, and the placing of the distribution assets into a master limited partnership. The utility has been ezperiencing financial hardship largely as a result of building capacity that has left it with a 70 percent reserve margin. Under the proposed restructuring plan, the distribution company (or disco) would remain subject to state retail rate regulation, but the generation company (or genco) would be subject to regulation by the Federal Inergy Regulatory Commission (FERC) under the commission's authority to regulate wholesale power sales. The strategy behind this proposal, according to the company, is to refinance the company's assets in a way that will allow it to reduce electric rates for customers while giving the utility additional flezibility to remain competitive and to pursue non-utility investments. It is also clear that the utility sees the proposal as a way to differentiate its securities based on their risk characteristics. The propo~al takes into account "the recognition that there are different levels of risk associated with the different elements of the traditional utility," says David Rusk, PSNM's manager of issue analysis and corporate communications. "In general, the generation side, particularly for companies with new p~~nt and especially nuclear plant, represents the riskiest side of the business," notes Rusk. "The distribution system has relatively lower risk. Yet, as an integrated company, the market generally attributes to your capital structure the risk associated with the riskiest element." 29 It seems almost inevitable that more utilities will propose restructuring plans involving vertical disintegration, although the prospects for regulatory 33
PAGE 38
approval remain much less certain. "Many utility chief ezecutive officers and chief financial officers are paying close attention to the efforts of PS Co. of Nev Mezico," says Ernest Liu, a utility analyst with Goldman Sachs & Co. 30 In fact, at least two additional utilities--Portland General Electric Co. and Pacific Gas & Electric Co.--have recently proposed reorganizing their business units along lines that would facilitate their later adoption of vertical disintegration plans. "Increasingly we will see a disintegration of electric operations into companies that emphasize either generation or distribution," predicts John Sawhill, a director of the management consulting firm Mcltinsey & Co. "And while there may be a limited number of completely specialized entities--such as regional wholesalers--all utilities will become somewhat mtlre specialized." 3l Layaragad bgoutss Leveraged buyouts are another type of restructuring activity that the electric power industry is examining Leveraged buyouts (LBOs) involve a small group of investors buying out a company's public shareholders at a premium, usually using the company's asset base or cash flow to support a highly leveraged capital structure. LB0s usually involve the target company's existing management, but they can sometimes be undertaken by outside investors. To date, there has not been any significant leveraged buyout activity in the electric power industry. Nevertheless, speculation about future LBO activity involving electric utilities has been quite active over the past two years. The management of Alamito Co., a wholesale generating company spun out from Tucson Electric Co. in 1984, proposed an LB0 in 1985 but was eventually outbid by an outside investment group. In addition, an informal offer by an investment group for a buyout of Public Service Co. of Indiana in late 1986, which received an unfavorable response from the utility's management, was 34
PAGE 39
based on the concept of a cash flow LBO with management participation. There have also been reports in the financial press that FPL Group, the holding company for Florida Power & Light, rejected a friendly LBO proposal in 1986. There is considerable debate among utility analysts over whether utility LBOs are feasible, but a number of utility ezperts believe that leveraged buyouts involving existing utility managers are the type of transaction most likely to succeed. Much of this speculation appears to have developed because most utilities gualify extremely well under the financial criteria used to screen potential LBO candidates. "Utilities, with their excess capacity, for the first time in our lifetime have become cash generators," says Martin Whitman, an investor involved in a restructuring effort at Pul)lic Service Co. of New Hampshire. "All utilitiee at rook bottom have stable earnings power. That's the stuff LBO are made of. One-third of the utilities I looked at, I could mostly finance an LBO at today's rate by cash flow," says Whitman. 32 Douglas Hawes, an attorney with the New York firm LeBoeuf, Lamb, Leiby & MacRae and a leading azpert on the Pul)lic Utility Holding Company Act of 1935, foresees considerable regulatory opposition to utility LBOs but acknowledges their economic attractiveness. According to Baves, wb t underlies "the substantial efforts currently being expended on LBO transaction proposals is that the economics are such that there is room to offer the state PSC either a reduction in rates for consumers or at least a rate increase moratorium. Moreover," says Hawes, "fully convincing arguments cmi be made that when there are not substantial cash requirements for construction during the period of the amortization of the LBO debt, greater leverage is not unreasonable, especially when the equity and LBO senior securities (debt and preferred) are to be held by highly sophisticated investors." 33 Not everyone beli~ves that leveraged buyouts will be feasible in the utility industry or is enthusiastic about their possible effects. Gary Neale, 35
PAGE 40
chairman of Plamnetrics Inc., argues that there are valid reasons why LBOs have not come to pass. "The simplest way to finance an acquisition is with stock," says Neale. "I don't know of any valuation technique that will forecast what regulators will do in a leveraged finance situation. I can't explain regulatory risk to investors, nor can I explain that if I run the utility better, returns will drop. So it's difficult to do any kind of leveraged financing in the ~,tility world." 3 4 "I suspect you may see a run at a leveraged buyout of a utility in the next few years," adds Douglas Randall, vice president for utility ratings at Standard & Poor's Corp. "There' s no reason to think si.ze would be any barrier to a leveraged buyout. It would be the largest descent of. debt from high grade to high yield in the history of junk bonds," Randall says. "I wouldn't want to be served by a utility taken over in a leveraged buyout," Randall said. "They would have to raise revenues and cut expenses to finance debt. And if you have no commitment to service, there's no limit to the expenses you can cut." 3 5 Jagptiatad NfCJllfll Negotiated, or "friendly," mergers between utilities are likely to be one of the most significant types of utility restructuring activity. Interest in negotiated utility mergers by the financial community has become almost feverish. There are several reasons why friendly mergers are seen as more likely to occur than hostile transactions, includinr the need to share benefits nong several competing constituencies and to obtain regulatory approvals. "A negotiated transaction is free of the inefficiencies and lack of mutual benefit often characteristic of a unilatei:al transaction," contends William Gremp, a managing director of Merrill Lynch Capital Markets, and consequently "encourages a result in which maximum potential benefits are achieved for customers, shareholders or members, and management." 36 Although actual merger and acquisition activity has not lived up to many 36
PAGE 41
people's ezpectations, there are signs that the pace of activity has begun to quicken, as can be readily seen in Table 9. Three significant negotiated mergers involving investor-owned utilities have occurred in the past two years: a merger that was completed in 1986 in which Cleveland Electric and Toledo Edison became Centerior Energy Corp., a definitive merger agreement between PacifiCorp and Utah Power & Light that was announced in August 1987 but remains subject to regulatory approval, and a merger agreement that was announced in October 1987 in which The Southern Co. agreed to acquire Savannah Electric & Power Co. in a stock transaction. The utility managements involved in these merger agreements generally predict that their actions were a precursor of more such activity. "We believe this step will make us a pacesetter in an industry move to fewer but larger companies," says Toledo Edison chairman John Williamson. "The key word is competition--not just between utilities but among technologies, fuels and such things as on-site generation. We need to be bigger and stronger, so we can compete in the years ahead," says Williamson. 3 7 Meanwhile, there are a number of examples of recent merger activity involving small utility systems. In 1986, for instance, Iowa-Illinois Gas & Electric bought Sherrard Power Co., an all-requirements wholesale customer of Iowa-Illinois that served about 13,000 customers. Similarly, in the public sector, the Omaha Public Power District, the largest electric utility in Nebraska, is considering a merger with the Norris Public Power District, which serves about 12,000 customers in the southeastern part of the state.38 Opinion seems sharply divided among other industry executives as to whether much merger activity is likely. A few utility executives have publicly pr,dicted a spate of merger activity. Jerry Geist, chairman of Public Service of New Mexico, warned an audience of utility executives rt the 1987 Edison Electric Institute annual conference that "if we don't restructure 37
PAGE 42
our industry ourselves, someone will do it for us." The industry "has a truly astonishing number of small, vertically integrated companies that are ripe for disaggregation and consolidation," said Geist. "My guess is that this path will become more attractive once regulators and customers realize the magnitude of possible coat savings from the vertical disaggregation and horizontal consolidation implicit in this path," he added. 39 But other industry ezecutives feel that the merger issue is being kept in the spotlight mainly by investment bankers and consultants trying to drum up business, and that there will be relatively few utility mergers. Moreover, industry surveys suggest that, as a whole, industry ezecutives are relatively unconcerned about mergers and other structural issues. For instance, a survey of top executives from 60 utilities in 1987 by Cresap, McCormick & Paget, a Chicago-based management consulting firm, found that concerns about merger activity ranked well below a number of other strategic issues. Just as opinions are sharply divided among industry executives on the issue of mergers, so too is there little agreement among utility analysts and investment advisers on the subject. Some industry analysts predict a tremendous wave of consolidation within the next few years. Edward Tirello Jr., senior utility analyst at Shearson Lehman Brothers, argues that "companies with the cheapest source of power generation and the strongest transmission lines will take customers away from weaker neighbors, thereby forcing the industry to consolidate." Tirello predicts that of the 150 major investor-owned utilities in the nation, "five years from now there will only be 50." 40 Other analysts foresee some merger activity, but are more cautious in their appraisal of the number and timing. "We'll see lots of idiosyncratic situations regarding merger and buyout activity," says Gregory Enholm of 38
PAGE 43
Table 10 Chronology of Significant Utility Merger and Takeover Events Jupe 1985: Cleveland Electric Illuminating Co. and Toledo Edison Co. announced their intention to merge. In April 1986, the merger was finally con~unnated, resulting in the formation of a holding company called Centerior Inergy that acquired the stock of both operating utilities. Hoyambar 1985: The management of Alamito Co., a wholesale power generation company previously spun off from Tucson Electric Co., proposed to take the company private in a leveraged buyout. In 1986, afte-a protracted bidding war, a subsidiary of Catalyst Energy Corp. outbid Alamito's management and other bidders, gaining control of Alamito. 1984 through 1987: UtiliCorp United Inc. made a string of small acquisitions. Over the past three years, UtiliCorp acquired three small gas utilities and two small electric utilities--Nest Virginia Power, and West Kootenay Power & Light. October 1986: An investor group including former EPA administrator William Ruckelshaus and former Illinois Commerce Commission chairman Philip O'Connor reportedly made an informal cash bid of $17 per share for Public Service Co. of Indiana stock. The company was apparently not receptive to the proposal and it was dropped. Dacembar 19861 Millionaire investor David LaRoche made a hostile tender offer for a controlling interest in Newport Electric Co. The utility responded by reorganizing as a holding company, NECO Enterprises, after LaRoche's offer failed to attract a majority of the outstanding shares. LaRoche conmenced a second tender offer for RECO's shares in March 1987 and, by late July, held 50.1 percent of NECO's common shares. July 1987: Thomas Bruce, a Boston stockbroker, announced he was trying to garner support from anti-nuclear groups for a takeover of financially beleaguered Public Service Co. of New Hampshire, the chief owner of the Seabrook nuclear power plant. Two other groups of PSNH debtholders also began attempts to gain control of the utility. August 1987: PacifiCorp and Utah Power & Light Co. agreed to merge, citing prospects for increased efficiencies from operating as a combined company. The merger is subject to regulatory approval. September 1987: Pacific Gas & Electric Co. submitted a proposal to the Sacramento Municipal Utility District (SMUD) to buy all of SMUD's facilities and to close down the troubled Rancho Saco nuclear plant. October 1987: Southern Co. agreed to acquire Savannah Electric & Power Co. for stock at a price of almost twice Savannah Electric's book value. Source: Investor Responsibility Research Center 39
PAGE 44
Salomon Brothers. "It will probably follow the same pattern we saw with diversification, with a few deals at first and then more happening later." 41 "Some utilities will be driven to "strategic" mergers that will offer opportunities for improved performance in terms of operations, finance, administrative savings, strengthened management and generation planning, agrees management consultant John Sawhill. But Sawhill predicts that merger activity will not be widespread, becau~e many utilities will improve performance without resorting to formal mergers and because of the "added difficulty of justifying paying a premium for a company in a regulated industry." 42 "I don't ezpect wholesale mergers because the regulators are watching," adds Leonard Byman of Merrill Lynch. "But there will be some opportunities," Ryman says--including "shotgun marriages" for troubled utilities and the possibility of takeovers of portions of utilities if investor-owned utilities split themselves into generating companies and distribution companies. 43 A number of other utility analysts and consultants are even less sanguine about the prospects for many utility mergers. Merger and takeover talk has "been very overhyped," contends Drezel Burnham Lambert managing director John Kellenyi. "There will be some merger and acquisition activity, but we're more likely to see internal restructuring," says Kellenyi, and "the pace will be evolutionary, accelerated or retarded by key regulatory events." 44 If utilities "haven't learned how to play the regulatory card well and the consumer card well, then there probably will not be a merger," adds Jassi S. Cheema, senior vice president of Theodore Barry & Associates. From Cheema's perspective, the industry is probably heading for more "quasi" mergers--informal arrangements to plan capacity and dispatching needs in response to "least-cost" planning initiatives, rather than true mergers. 45 40
PAGE 45
Hostile Nrmttl and takaoyers: Another type of restructuring that may play a role in the utility industry is hostile merger and takeover activity. At present, two significant hostile takeover attempts are developing on the investor-owned side of the industry: an attempt to take over NECO Enterprises, the holding company for Newport Electric Co., and attempts by several parties to gain control of financially troubled Public Service Co. of New Hampshire. In the case of NECO Enterprises, private investor David LaRoche began pushing a takeover attempt in December 1986. LaRoche, who was reported to be interested in a certain waterfront parcel of undeveloped real estate owned by the utility, undertook two partial tender offers to NECO's shareholders in 1986 and 1987 and, when combined with purchases of the company's stock on the open market, was able to secure ownership of 50.1 percent of RECO's common stock by July 1987. Then, in December 1987, LaRoche announced that he had reached an agreement to sell his controlling interest in HECO to Eastern Utilities Associates (BUA), a utility holding company headquartered in Boston. BUA reportedly wants to acquire the remainder of NECO stock in a friendly merger, but it would launch a tender offer if NICO did not agree to an acquisition. Despite the antitakeover measures that NECO Enterprises has in place, including its organization as a holding company, LaRoche's majority ownership position meant that it was inevitable that he would have eventually acquired control of lfECO, says PUBCA ezpert Douglas Hawes. "If an individual has sufficient resources to acquire utility shares without creating an acquisition vehicle and leveraging it, '35 Act problems can be avoided," notes Hawes. "That is because the '35 Act only applies to holding companies and a natural person is virtually the only person that does not constitute a 'company' as defined in (PUHCA) Sec. 2(a)2." 46 If successful, a takeover of NECO Enterprises would be notable in that it would be the first hostile takeover of an investor-owned utility in several decades. 41
PAGE 46
In a more fluid and leas organised situation in the State of Hew Hampshire, several groups appear to be considering hostile takeover or restructuring attempts at Public Service Co. of New Hampshire (PSNH), which is also saddled with a completed nuclear power plant that has been UDable to operate because of fears relating to evacuation procedures. In a July 1987 article in the Boston Globe* Thomas Bruce, a stockbroker with Paine Webber Corp. in Boston, said he was trying to gain the support of anti-Seabrook activists for a takeover of Public Service Co. of New Hampshire. In October 1987, however, the utility decided to default on a $37 million interest payment, perhaps paving the way for its mortgage bond and debenture holders to force it into involuntary bankruptcy. The debt payment suspension has resulted in a recapitalization plan being proposed for PSHB by Consolidated Utilities and Communications Inc., a Hew York firm representing a consortium of PSNH bondholders. Public versus private poyar takagyer battles: A final type of restructuring activity underway is a variety of battles involving attempts by city or state governments to gain control of investor-owned utilities and attempts by investor-owned utilities to gain control of publicly owned utilities. Interestingly, the catalyst for a number of these takeover situations appears to be a series of troubles related to nuclear plant construction or operation. In Hew York, Gov. Mario Cuomo and the state legislature are pursuing an effort to allow a new public power authority to take over Long Island Lighting Co. (Lilco) as a means of assuring that the Shoreham nuclear plant will never operate. The state agrees with county and local officials that it would be impossible to evacuate the area surrounding the plant in the event of a nuclear accident. In 1986, New York passed a law in 1986 creating a Long 42
PAGE 47
Island Power Authority (LIPA) to study whether it could provide power at rates cheaper than Lilco and, if so, empowering it to acquire the utility either through negotiations or through condemnation of the utility's property through eminent domain. At present, the Lilco takeover battle is being fought primarily on the issue of whether a state takeover would result in lower rates to electricity consumers. The state has connissioned studies which purport to show that rates would be lower under a LIPA takeover, while Lilco has released studies arguing the opposite. A decision on the matter is ezpected by early 1988, although many analysts remain skeptical of any quick resolution of the issue. A number of city governments are also looking at the option of municipalization of investor-owned electric distribution systems. In Chicago, city officials are reported to be mulling several options with regard to buying out or bypassing Connonwealth Edison's power system. The city's franchise agreement with the utility expires at the end of 1990 and city officials are unhappy with electric rates, which have risen siz times in the past 10 years and threaten to go much higher as Commonwealth Edison tries to include the costs of several new nuclear units in its rate base. The late Chicago mayor Harold Washington had called the formation of a municipal power agency "one of the most challenging options" for the city. 47 City officials in Hew Orleans; Gilbert, Ariz.; and Albuquerque, N.M., are also studying the municipalization option. In addition to these situations involving possible takeovers of investor-owned utilities, there appears to be considerable potential for what are essentially takeovers of municipally owned and cooperative electric systems by the investor-owned sector. One such situation is developing in California, where Pacific Gas & Electric proposed a buyout of the Sacramento Municipal Utility District (SMUD), one of the largest municipal 43
PAGE 48
electric systems in the country. SMtJD has faced considerable difficulties stemming from the prolonged outage of its Rancho Seco nuclear plant. Rancho Seco has been out of commission since December 1985 after an overcooling incident shut the plant down. SMUD has been struggling to restart the reactor--which has a trouble-plagued history--but meanwhile has watched its rates rise 60 percent since 1985 as it has bean forced to replace the lost power with purchases from other sources. In September 1987, PG&E made a proposal to SMOD to "consolidate" SMUD into the PG&E system while permanently closing the Rancho Saco plant. Public and private reaction to the PG&E plan by SMtJD officials and its board was negative, however, and PG&E withdrew its proposed bid in January 1988 citing SMUD's "failure to give serious consideration" to its consolidation proposal. 4 8 SMUD is reportedly ezamining a number of options ranging from operating Rancho Seco, to selling it or converting it to a gas-fired facility, to a sale of all of SMUD's generation and transmission assets. 4 9 Similarly, Virginia Power is attempting to persuade seven municipal utilities to enter into joint studies on merging into the investor-owned utility. Meanwhile, legislation has been introduced in South Carolina that calls for sale of the state-owned Santee Cooper generating and distribution system to one of the state's investor-owned utilities. Proceeds from the sale, estimated to range as high as $4 billion, would form an endowment to help finance education budgets and universities in the state. SO Like the issue of utility mergers, the question of whether hostile takeovers are likely to become a common occurrence in the utility industry provokes intense debate among industry analysts and consultants--although those believing that there will be few hostile takeovers are a distinct majority. The issue that appears to separate those analysts who believe takeover activity is likely from a majority of their peers is how stifling the 44
PAGE 49
regulatory obstacles to takeovers will be. Mally analysts see these regulatory hurdles being too onerous to overcome for moat would-be utility acquirers. John Sawhill of McKinsay & Co., for ezample, says that the regulatory and legal barriers to takeovers will prove formidable and that while "you might see an outsider buy one electric utility, because of the company's cash generation, you will not see the amount of takeover activity suggested in the articles I've read." 51 "A close look at the facts shows that utility takeover talk is mostly smoke and only a little fire," adds Douglas Raves. Raves sees time as perhaps the biggest impediment to utility takeovers. "The Liggest problem is time, which is the biggest and beat defense of a target. I just don't think there will be many attempts at leveraged buyouts or takeovers in this industry, even by other utilities," says Raves." 52 This view that regulatory and other obstacles to utility takeovers will prove prohibitive ia by no means universal, however. "There are much greater obstacles to taking over utilities, with layers of regulation," notes Evan Silverstein, a former utility analyst at L.P. Rothschild, Unterberg, Tovbin who now manages the utility investments of the Bass Brothers. "But they won't be total obstacles, if [an acquirer] can show stockholders such a move is in their bast interest," says Silverstein. 5 3 "I think we're going to sea several hostile utility takeover attempts," agrees Marc Becker, an attorney at Stadden, Arps, Slate, Meagher and Plom, "and I don't mean Alamito-type deals, I mean old-fashioned takeover attempts." 54 45
PAGE 50
Chapter III1 Inveataent Coaaunity Viewa on Utility tructuriDCJ The following findings are based on a series of interviews with members of the investment community who have substantial ezperience with the financing of the electric utility and small power industries. Much of the financial conaunity sees large industrial customers as the primary destabilizing influence on the ezisting utility system. This influence takes a nwnber of forms, including industrial cogeneration, the threat to move facilities between service territories or to add new facilities and jobs where utility rates are low, and the political and social clout to affect how rates are set. Investors believe that industrial customers have developed a new mindset toward utility rates--a mindset that views these rates as a variable that can be altered--that will be impossible to turn off. Investors ezpect the nezt major area of confrontation between industrial customers and utilities to center around the issues of wheeling between industrial facilities and access to the transmission grid. Many investors say that the government should take a long hard look at what has happened in the electric power industry in recent years and~ before they embark on any major changes in the industry's ezisting regulatory system. There is considerable wariness about need for major changes and about the likely results of virtually any type of massive government rewrite of utility regulation. Investors argue that lawmakers and regulators tend to view the industry's situation through a prism that reflects past, rather than current, problems and that it is unrealistic to suppose that someone will devise a perfect formula for fixing the 46
PAGE 51
induatry'a current problema. Some inveatora are very akeptical that competition can serve as a substitute for regulation in the electric power industry unless regulators are willing to do away with utilities' obligation to serve all customers. These investors say that the government is currently a "destabilizing" force in the industry, when it should be working to stabilize the system. Other investors welcome the prospect of a less regulated environment for utilities and believe that the market should be allowed to dictate the future direction of the industry while government helps the process along by providing flezibility during the transition phase through actions such as a loosening of the restrictions in the Public Utility Bolding Company Act. e To the eztent that changes All made, there appears to be some preference among investors that these changes be made at the national level, rather than allowing each state to operate with a different set of rules. In general, investors feel that the Federal Inergy Regulatory Connission (nRC) is fairer to investors than most state regulatory connissions. They also tend to view the FIRC as less politicised than the Congress and prefer that any overarching changes in utility regulation be made under FIRC guidelines, rather than through congressional action. Similarly, while they would prefer to see the government's involvement in regulating financial restructuring activity kept to a minimum, investors tend to prefer that any regulation of this type of activity be done at the federal level--either through FERC or through the SIC--rather than through state PUCs. A minority of the investors interviewed preferred that state regulators take the lead in this area, fearing that FERC or the Congress might impose overly specific rulemakings that would limit the flexibility of utilities 47
PAGE 52
to respond to local conditions. Some institutional investors are skeptica~ of the common assumption of a capital availability problem in the electric power industry. Some investors believe that utilities and their investors misunderstood the nature of the regulatory "social compact" fro the begiDDing. They say that regulators promised only to allow utilities to recover the lower of actual costs or market price, and that now a period of adjustment is needed as the mL~ket price of power has fallen below its cost for some high-coat producers. Other investors do believe that regulators have indeed broken the "social compact" with utilities and their investors. Reverthelesa, most investors do not believe it will be difficult for the industry as a whole to continue to raise substantial ounts of capital for the next cycle of plant conatruction--albeit in smaller increments than the 1,000 MN plants of the last cycle. Rather, investors tend to view any capital availability proble11a as related to certain readily identifiable a94J1Nnta of the induatry, 1nclu41nga 1.) Bztraordinary and perhaps temporary situations--especially those involving utilities that have well-publicized financial difficulties relating to troubled nuclear plants such as Long Island Lighting Co. and Public Service Co. of Rew Hampshire. 2.) Utilities that must operate in states with elected regulatory commissions that may view utility rates as a political matter. 3.) Small power producers (either QFs or IPPs) that lack a sufficient 48
PAGE 53
track record, reputation and/or capital base to provide a sufficient level of comfort to investors. This would not apply to large, established independent power producers or consortiums involving healthy utilities. e A nwnber of investors believe that some of the state regulatory and pricing concepts currently being ezperimented with will prove unworkable. There is some skepticism that the PUBPA model can work in a competitive operating enviromnent where buyback rates have fallen low as 3-4-Jnrh. There is even 1110re skepticiam that many competitive bidding schemes for procurnt of new generating capacity will prove workable--primarily because they result in contract awards baaed almost entirely on price, without proper attention to the ~ualificatione of th bidders or to the service aapecta of power supply. On major inveating institution stated that "of th four competitive bidding awards made so far, none are financeable." 55 Investors also note the trend toward utilities demanding that non-utility projects be subject to utility dispatch and wonder how people aspect them to provide non-recourse project financing for projects whose revenue streams are subject to utility dispatch. Some investors believe that the previous system of negotiated contracts was a superior system because it allowed greater flezibility than do competitive bidding systems. Some investors also worry that the competitive bidding concept, although it is supported by many utilities, will ultimately come back to haunt utilities if they end up short of power. Investors believe that if utilities award power purchase contracts to unqualified bidders, these projects will eventually fail, and regulators will attempt to penalize 49
PAGE 54
the utilities for not adequately meeting their service needs. Investors strongly believe that active utility participation in the construction of new generation provides a level of comfort to investors that is very important to the financing of substantial projects. The believe that joint independent power projects involving utilities and "name brand" construction and engineering firms or other non-utility power developers will have little trouble obtaining attractive financing. Regarding the five regulatory scenarios outlined by the Office of Technology Assessment, there is considerable doubt among the majority of financial institutions interviewed that any of the scenarios involving new rules would be superior to the status quo from the perspective of reducing risk to investors or providing greater capital availability to the industry. Investors tend to regard fully integrated utilities that retain a monopoly on all aspects of the business as the least risky proposition. The general perception is that each of the OTA scenarios involving expanded competition on the generation side of the business or greater transmission access progressively chips away at the monopoly franchise concept, thereby subjecting the investor to greater market risk. Investors say that each step down this path of increased market risk would have negative implications for utility credit ratings and would require commensurate increases in the return required by investors in order to participate in financing the industry's capital needs. OTA scenarios 4 and 5 would result in very high cost financing, investors say, with the total returns required by investors under these scenarios equal to the returns for fully competitive industries using equity or junk bonds to obtain capital. 50
PAGE 55
A minority of investors interviewed reject the above thesis, arguing that most of the business risk in the electric power industry has arisen from fundamental changes in the external environment that cannot be undone. Begulation has changed from a risk mitigator to a source of added risk, these investors acknowledge, but the reason is not that regulators have just decided, en masse, to punish investors, but that external conditions have forced them to take new approache~. These investors tend to see opportunities in the changes takJng place, and to believe that hoping for a return to a monopolized, risk-free investment atmosphere in the electric industry is akin to hoping for a return of the dinosaurs. They maintain that if the policy objective is to provide a stable environment for bringing new capacity on line, a competitive system will do it better than an attempt to resurrect the old regulatory compact. There is some difference in the perspective of equity and debt investors with regard to the willingness to provide capital to th industry under a changed regulatory system. In general, equity investors believe that any set of rules changes will have a selective impact on different players in the industry--thereby providing new investment opportunities as well as investments to avoid. Equity investors are looking to find "an angle" on the industry to play. Equity investors believe that most of the OTA scenarios vould have a differential effect on the industry--helping low cost producers at the expense of high cost producers. Equity investors would look to profit from this differential impact by analyzing how different companies.would be likely to fare under the new set of rules and shifting their investments toward those companies that could take best advantage of a more competitive environment. 51
PAGE 56
Debt inveators, on the other hand, tend to see virtually any set of rules changes presently under consideration--including all of the OTA scenarios ezcept the status quo--as resulting in an increase in debtholder risk with no increase in reward. They note that huge amounts of utility bonds are outstanding, and that any regulatory change that weakens the monopoly franchise and makes the industry more risky can only result in a devaluation of these outstanding utility bonds based on the increased possibility of defaults. In other words, utility debtholders tend to see the e~isting regulated monopoly system as the most stable possible operating environment for utilities, and to see any movement away from this concept as resulting in increased business risk and declining credit quality. And unlike investors on the equity side, debt investors say there would be no "winners" in this new game, because many utility debt issues would be downgraded and few, if any, would be upgraded. Prom a credit ratings standpoint, one analyst believes that under the more competitive business conditions that would result fr0111 most of the OTA scenarios, utilities would have no choice but to increase the levels of equity in their capitalization structures if they wanted to maintain their existing credit ratiJgs. 56 Investors tend to see utility financial restructuring as a symptom of an industry that is encountering financial problems resulting from excess capacity. They believe that more financial restructuring activity will occur and that it has the potential to result in improved industry efficiencies. Some investors believe that financial restructuring can, over time, make a major contribution to solving the fundamental problems faced by high-cost producers in the industry. They see sale-leasebacks, vertical disintegration, mergers and other restructuring activities 52
PAGE 57
eventually narrowing the cost-of-service differences among utilities. Other investors, however, dismiss financial restructuring as little more than a shell game that will have little impact on solving fundamental problems. From a credit quality perspective, investors say that debt-financed restructuring would have negative credit implications, but mergers between equally rated utilities would probably not have much impact on credit ratings. Mergera could also have positive implications for the merging utilities (especially if they resulted in greater market power) while havinq negative implications for the competitors of the merged entity. Utility sale-leaaeback deals will have negative implications for credit guality unless the full proceeds are used to pay down other debt, analysts say, because the lease obligations will be treated as debt equivalents. e There also appear to be some philosophical differences between investors who have participated in the power industry chiefly through financing non-utility power developers and those who provide capital primarily to utilities. Utility investors tend to see government involvement in the industry through regulation as a safety net that, ezcept where it has become overly politicized, lessens their risk. Investors in non-utility projects, however--while recognizing PURPA as being important to get the industry launched---now see further deregulation of the electric power arena as offering the greatest opportunities for growth in the non-utility power generation business. s7 Members of the financial community believe that providing project financing in the electric power area has essentially become a highly competitive commodity-type business. They see the field attracting a 53
PAGE 58
large number of new financial institutions that have varying motives for getting involved in this area. They say that Japanese and European financial institutions, many of which have ties to manufacturing companies, have become quite active in the small power and utility financing area. Some investors see this influz of foreign capital as a positive development, resulting in lower financing costs for all participants in the industry. Others, particularly major domestic lenders, complain that foreign investors are undercutting their business and are doing deals at below-market rates as a way of buying market share in the business and of acquiring knowledge that will allow them to become more competitive manufacturers of technologies developed in t!Ae United States. 54
PAGE 59
Aaandis A List of Persons Interviewed or OTA Report Gregory B. Bnholm Utilities Analyst Salomon Brothers Inc. One New York Plaza New York, NY 10004 (212) 747-7830 James T. Doudiet Managing Director Corporate Finance Dean Witter Reynolds World Trade Center, Tower #2 New York, HY 10048 ( 212) 524-2758 Maria Richter Counsel, Utilities Group PruCapital Three Gateway Center 100 Mulberry St. Newark, NJ 071022 (201) 877-3918 Steven M. Thompaon Utility Account Manager, laatern Region PruCapital Three Gateway Center 100 Mulberry St. Newark, NJ 071022 ( 201) 877-3918 Thomas Mockler Standard & Poor's Corp. 25 Broadway New York, NY (202) 208-8000 Philip R. O'Connor Chairman and President Palmer Bellevue Corp. 111 w. Washington St., Suite 1320 Chicago, IL 60602 ( 312) 807-4848 55
PAGE 60
AlmelY'1g I Glossary of Ipyastmant Terms Assetor credit-based financing--Financing where funds are invested or lent baaed on the ezistence of physical assets that can serve as collateral. Utility mortgage bonds, where the utility's physical assets serve aa collateral, are an ezample. Pipancial leyeraqa--Th use of borrowed money in a transaction. Highly leveraged financings can involve up to 90 to 100 percent debt financing~ with little or no equity component. Jupk bopds--High coupon rate junior debt securities that typically have below investment grade credit ratings. Master limited partnership--Publicly traded partnerships that offer the advantages of partnership-type investments (direct owership of assets and a proportionate share of income, losses and taz deductions generated by the partnership) while providing the liquidity that is often lacking in conventional partnership investments. Project fipapcing--A type of financing where the lender looks primarily at the cash flow and assets of a specific project, rather than at the credit~1orthineas of the borrower. Powerplant project financings rely on tightly drawn contractual arrangements among the various participants in a project--auch as the project developer, fuel supplier, vendors and constructors and the entity purchasing the power. Racapitalization--Financing activities that change ~he capital structure of a company or an asset. Rastructuring--A somewhnt catch-all phrase encompassing activities designed to change the organizational or financial structure of a business. Sala-leaseback--A financing arrangement where one party--typically a bank, insurance company, corporate financing subsidiary, or leasing company--purchases and finances an asset from the owner and leases it back to the owner/operator under a long-term contract, with specified rental payments to cover interest and principal on any debt in the capital lease structure, plus a nominal cash return on the equity. Tombstone adyertisaments--Box-shaped advertisements run in financial newspapers and magazines by financial firms involved as principals or advisers in securities offerings or other financings. 56
PAGE 61
aotes l Scott Fenn, Mergers yd Financial Restructuring in the Electric Power Indust,y (Investor Responsibility Research Center, Washington, D.C., 1988); and Scott Fenn, Institutional Investment ip Renewable Energy Technologies (Investor Responsibility Research Center and Renewable Energy Institute, Washington, D.C., 1987). 2 Scott Fenn, America's Electric Utilities; (Praeger, New York, 1984), p. 31. Under Siege and in Transition, 3 See for instance Electrical World. "1987 Annual Industry Forecast," September 1987, p. 42. 4 See for instance, Scott Fenn, Douglas Cogan and Susan Williams, Power Plays; Profiles of America's Leading Renewable Electricity Producers (Investor Responsibility Research Center, Washington, D.C., 1986); and "Profile of Cogeneration and Small Power Markets," Hagler Bailly & Co., 1987. 5 Several problems are inherent in the tombstone ad methodology used by NAESCo. First, many financings in the private placement market, including some large ones, never appear in any tombstone ads and hence are never included in the NllSCo totals. Second, some financings for the same project may be advertised by several of the underwriters or principals, possibly resulting in double-counting. Likewise, use of short-term construction loans or bridge financing may also result in double-counting. 6 see Scott Fenn, Institutional Investment ip Renewable Energy Technologies, gs.~7 1Ju4.; and Bill Paul, "Renewable Bnergy Concerns Begin Attracting Big Institutions Betting on Another 011 Crisis," D Wall Streat Journal, April, 16, 1987. 8 Philip O'Connor, "Electricity The Final Monopoly?," paper presented at PUB/Management Bzchange conference on utility mergers and acquisitions, Arlington, Va., April 3, 1987. g "PIRC Staff Proposals Launch Full-Scale PURPA Debate on Competitive Bidding," solar 1n1rgy Int1111genc1 Report. Vol. 13, No. 35, Sept. 15, 1987, p. 280. lO Power Plays.~dt,.; Douglas Cogan and Susan Williams, Generating Energy Alternatives; 1987 Edition~ Investor Responsibility Research Center, 1987; and "Profile of Cogeneration and Small Power Markets," Hagler Bailly & Co., 1987. ll George Melloan, "Is a Free Market for Electric Power on the Way?," ThL Wall Street Journal, June 2, 1987, p. 31. 1 2 See for instance "Photovoltaics for Utilities," EPRI Journal, January/February 1987; and "Comparing Advanced Technologies," EPRI Journal, July/August 1987. 13 See Douglas Cogan and Susan Williams, Generating Energy Alternatives: 1987 Edition,~a,t. 57
PAGE 62
1 4 Boward Geller, .. Bnergy and Bconomic Savings from Rational Appliance Efficiency Standards," American Council for an Inergy-Efficient Bconomy, March 1987. 15 See Amory Lovins, "Saving Gigabucks with Negawatts," Public Utilities Fortnightly. March 21, 1985, pp. 19-26. 16 For a discussion of the importance of this concept in the residential market see "Inside the Smart Bouse," EPRI Journal, November 1986; 17 25. "U.S. Nuclear Plant Statistics," Utility Data Institute, August 1986, p. l8 See for instance Gail Garfield Schwartz, "A Hey Deal for Telegonnupigation1~" Public Utilities Fortnightly, Nov. 27, 1986, p. 13; and Paul r. Levy and v. Louise Mccarron, "Free the Local Telephone Companies," Public Utilities Fortnightly, lruly 10, 1986, p. 13. 19 22. Sarah Bartlett, "Debt in the Danger zone," Business week, Aug. 4, 1986, p. 20 Connents at the PUR/Management Bxchange conference on utility mergers and acquisitions, Arlington, Va., April 2, 1987. 21 Douglas Dunn and Bernard Topper, Jr., "Terms and Conditions for Electric Utility Success with Leveraged Lease Financing," Public Utilities Fortnightly# April 16, 1987, p. 14; and Barry B. Burr, "Utility Gets Aggressive with Cash from Sale-leaseback," Pensions and Investment Age# March 9, 1987, p. 9. 22 "Sale/leaseback Deals Providing Utilities New Capital and Lower Financing Costs," Electric Utility Week# Jan. 13, 1986, p. 2. 23 David G. Crane, "Behind the Increasing Use of Lease Financing by Utilities," Public Utilities Fortnightly# Feb. 19, 1987, p. 24. 2 4 Paul Ingrassia, "CMS to Inter Nuclear Venture With Bechtel," The Wall street Journal. Oct. 8, 1987, p. 8 25 "In Reversal, FBRC Gives Go-ahead to GSU/Industry Cogeneration Venture," Electric utility Hk# May 18, 1987, p. 16. 2 6 Donald Marier and Larry Stoiake!!l, "The Utilities: Partners or Adversaries, Alternative sours; of Energy# May/June 1987, p. 18. 2 7 "Partners in 2,000-Mlf Dinah Plant Seek Buyers of 1,000-MW Before Building," llctris; Utility WeaJc. June 8, 1987, p. 3; and "Sierra Pacific Joint-Venture Proposal for 2,000-MW Plant Sparks Opposition," Electric Utility !llilk, June 15, 1987, p. 1. 28 Bill Richards, "Commonwealth Edison's Plan to Form Nuclear-Plant Unit Rejected by Agency," The Wall Street Journal, July 3, 1987. 2 9 '"Unbundling Proposal by PS New Mexico Confines PSC Regulation to Distribution," Electric Utility Week, March 2, 1987, p. 1. 30 Paul Duke Jr., "PS New Mexico Weighs Partnership For Its Electric Distribution System," The Wall Street Journal, March s, 1987. 58
PAGE 63
31 "Preaaur of Competition Seen Leading to 'Disintegration' Of Industry," Electric utility lk April 21, 1986, p. 1. 32 Barry Stavro, "High-voltage Action," Forbes, Mays, 1986, pp. 48-49. 33 Douglas Hawes, "Utility Takeovers1 Considerable Talk, Not Much Action," The Legal Times. Oct. 20, 1986, pp. 13-16. 34 Coments at Institute for International Research Utility Restructuring conference, Rew York City, Sept. 21, 1987. 35 "Perceived Threat of Takeovers Spurs 17 Utilities to Set 'Shark Repellent'," 111ctric Utility waet. May 12, 1986, p. 1. 36 Speech presented at PUR/Management Bzchange conference on Utility Mergers and Acquisitions, Arlington, Va., April 2, 1987. 37 "More Consolidations Seen on the Way in Wake of CBI-Toldedo Bdison Merger," Blectric Utility week. July 1, 1985, p. 1. 38 "Small Investor-owned Utility's Shareholders Okay Merger With Iowa-Illinois G&B," Electric Utility Week. Sept. 22, 1986, p. S; also "Santee Cooper, Central Electric Power Co-op Merger Urged by Advisory Panel," Elac;tric Utility Weak. Oct. 13, 1986, P 7. 39 "PS New Mezico Chairman Sees A Pressing Need for Industry Restructuring," Electric Utility week. June 15, 1987, p. s. 4 0 Vartanig G. Vartan, "Analysts See Utility Mergers," The Rey York Times., July 31, 1987, p. D4. 41 Telephone conversation with Greg Bnholm, Oct. 26, 1986. 42 "Pressures of Competition Seen Leading to 'Disintegration' of Industry," Electric Utility week, April 21, 1986, p. 6. 4 3 Connents to PUR/Manage111ent lzchange conference on utility mergers and acquisitions, Arlington, Va., April 2, 1987. 4 4 "Hostile Takeover Talk Markedly Diminished at Restructuring Conference," Electric; Utility Wttk, Oct. s, 1986, p. s. 4 5 Comment to PUB/Management Bzchange conference on utility mergers and acquisition, Arlington, Va., April 2, 1987. 4 6 "LaRoche Takeover of NICO Enterprises 'Seems Inevitable', Says Hawes," Electric; Utility Wk, Oct. 12, 1987, P 15. 47 Bill Richards, "Chicago Mulls Plan to Cut Electric Rates By Buying or Bypassing Utility's Plants," The Wall Streat Journal, Nov. s, 1987, p. 45. 48 "PG&E Withdraws SMUD Takeover Bids Claims No Serious Consideration'," Electric utility week, Jan. 18, 1988, p. 1. 59
PAGE 64
4 9 rrederict lose, "Pacific Gas Proposes a Consolidation With Big Sacramento Municipal Utility," Th wa11 straat Journal, Sept. 4, 1987; and "SMDD Officials 1811ain Cool to PG&B Takeover; Bye Rancho Seco Restart," Electric Utility Week, Oct. 12, 1987, P 13. SO "Legislation Calls For Sale of Santee Cooper to an Investor-owned Utility," llc;t;ric; Utility !lk Rov. 16, 1987, p. 7. 51 "Chances Slim for Hostile Utility Talceover--Even of Lilco, Sawhill Says," Blac;tric; Utility Week. Aug. 4, 1986, P 7. 52 DoWJlaa &awes, "Utility Takeovers: Considerable Talk, Rot Much Action," the Legal timt .. Oct. 20, 1986, pp. 13-16; and "Takeover Possibilities Play a Role in Pushing Up Utility Stocks in June," Blac;tric; Utility Week, July 7, 1986, pp. 5-7. 53 "Perceived Threat of Takeovers Spurs 17 Utilities to Set 'Shark Repellent,"' llc;;t;rig Utility Klr,, May 12, 1986, p. 1. 54 Coanenta at PUR/MaDa9e11ent lzchange conference on utility merger and acquiaitiona, Arlington, Va., April 2, 1987. 55 Conversation with Steven M. Thompson, PruCapital, Dec. 2, 1987. Also see "Bankers Say Many Winning Cogeneration Bide Are tJnfinanceahle," !ilegtrig utility waek. Dec:. 14, 1987, p. 16. 56 Conversation with Thomas Mockler, Standard & Poor's Corp., Rov. 23, 1987; see also "Sale/leaseback Deals Providing Utilities Rew Capital and Lover Financing Costs," ml J;,i,t. 57 See Scott Fenn, Institutional Ipvest;mant in lPtxAhl Energy Tac;hnolqgia~, ga. ~., PP 43-46. 60
PAGE 65
OTA DRAFT WORKING PAPER THE SITING OF EHV ELECTRIC TRANSMISSION LlNES MAY 1988 Prepared under Contract with the Office of Technolo1y Assessment by James S. Cannon 236 Montezuma Street Santa Fe, New Mexico This is a DRAFT OTA Workln1 Paper. It is beln1 circulated for review only and should not be quoted, reproduced, or distributed. The conclusions expressed in this report are those of the authors and do not necessarily represent -the views of OT A. This report has not been reviewed or approved by the Technology Assessment Board. ii\
PAGE 66
TU SIZIJIG or BBV IT:ICTBJC D1181JIIIQI LUI Prepared for the u.s. Office of 'l'echnology Aaseasment by James s. Cannon May 5, 1988
PAGE 67
'1'ABLB OP COWJ:BlffS Executive Summary . . . . . . . .. 1 Introduction .. 3 Overview of the IHV Transmission Network. .. 4 The Transmission Bottleneck 9 Si ting Procedures 13 Capacity Planning .. 14 State Certification and Licanaing 16 Local Pexmi ta and Approvals 20 Permitting Transmission Linea Across Federal Lands 21 Permitting Transmission Linea Across Tribal Landa 25 Multi-state Siting Efforts 27 Impediments to Transmission Li.ne Si ting .30 Obstacles to Transmission Line Approval ... 30 Jurisdictional Complexities 35 Lack of Multi-state Coordination 37 Interest Group Perspectives ......................... 39 Otili ty Companies .. 3 9 Government Regulators 40 Landowners and Affected Populations ..... 41 Ratepayer Consumer Groups .... 42 Environmental Organizations ... 42 Energy Systems Advoca tea .. 4 3 Options to Improve Transmission Line Siting. . . . . 45 Expanding the Planning Process Streamlining the Regulatory Approval Process. Involvement of Multi-state, Federal, or Independent .Agencies Enhanced Public Participation . . . . . 46 . .. 48 so ,, 52 Three Case Studies . . . . . . . 53 The Coal Creek Project The Ole Project The Washington DC Loop~ .54 . .59 . . .64 Conclusions . . . . . . . . . . . . .68 Dibliography. Footnotes . . . . . . . . . . . . . . . . . . . . . . . . 71 72
PAGE 68
EXECUTIVE SUMMARY The long distance transmission of electricity has increased significantly in recent decades. Power generation and sales predicated on long distance transmission can improve the financial positions of both the selling and buying utilities, absorb excess generating capacity, enhance system reliability, equalize power coats among regions, promote national environmental or energy security objectives, and postpone the construction of expensive new power plants. Thus, expanded use of long distance EHV transmission is a pivotal concept underlying many utilities' current electricity supply strategies and several proposals to restructure the industry to promote competition. Transmission capacity in some portions of the electrical grid is already strained by high usage and the pace of construction of new power lines has fall en over the past two decades. One possible reason for this is that the many licensing and certification processes required to site new transmission line projects can impede power line construction and sometimes lead to abandonments regardless of the merits of the projects. Long range planning efforts at the state level tend to focus on power generation issues, leaving interutility sales and long distance transmission issues understudied. Gaining approval of specific transmission line projects by state regulatory agencies OTA FINAL SITING REPORT Page 1 JAMES S. CANNON
PAGE 69
is a complicated process frequently requiring the filing and review of multiple applications. Constraints imposed by state utility laws and regulations hamper decisionmakers as they review large interstate transmission line proposals. Involvement of many local governmental agencies, the courts, and the federal and tribal governments further complicates the siting process and can lead to jurisdictional conflicts. The lack of multi-state siting procedures and coordination among federal agencies and agencies in different states further encumbers the siting of interstate power lines. A variety of interests groups have effectively entered the siting process for new transmission lines, although their involvement has frequently added to the time required to complete siting and to the complexity of the process. Proposals to improve the siting process for new transmission lines include developing more informati~n about transmission needs in the long range planning and application review processes, streamlining and clarifying state regulatory agency review processes, broadening multi-state siting efforts, and increasing public participation. Standardizing and expanding reporting requirements, increasing inter-agency coDD11unication, developing clear and consistent evaluation criteria, and creating new regulatory entities empowered to make final siting decisions could help achieve these objectives. OTA FINAL SITING REPORT Page 2 JAMES S. CANNON
PAGE 70
INTRODUCTION From the time the electric light bulb first illuminated Thomas Edison's laboratory in 1879, the transmission of electricity has been inextricably linked to electrical generation and use. With few exceptions, electrical transmission, utilizing alterna~ing current (AC). or direct current (DC) electrical fields, .have connected sources of electricity with power consumers. As the electric utility industry has grown, technological advancements have pei:mitted the construction of extra-high voltage (EHV) transmission lines capable of moving large volumes of electricity over long distances. This trend has accelerated in recent decades as long distance transmission has increased and the network of ERV transmission lines has broadened. The rise in long distance transmission promises to continue under a number of proposals to restructure the electric utility industry, assuming of course that transmission line construction keeps up with growing demand for long distance transmission services. The validity of this assumption is crucial to the fate of such restructuring plans, however, because transmission line construction projects can face an increasingly complex framework for regulatory agency approval and considerable public OTA FINAL SITING REPORT Page 3 JAMES S. CANNON
PAGE 71
opposition. This paper examines the procedures for siting and building EHV transmission lines in the United States. It explores the impediments to.power line construction and outlines the history of some recent transmission line projects which have experienced construction delays. Finally it discusses the often conflicting perspectives of interest groups towards EHV transmission, and some proposed remedies to alleviate the difficulties which face transmission line construction projects. OVERVIEW OP THE TRANSMISSION NETWORK For moat of the past century, electricity has been carried from producer to consumer by short-distance, low-voltage transmission and distribution lines. Nearly all electricity today is still carried to the final point of use by low-voltage lines. Beginning with the installation of the first extra high voltage (EHV) 345 KV line in 1952, however, more and more electricity has travelled farther distances in the United States on EHV lines These lines generally connect sources of power generation with power distribution networks of low-voltage lines near the points of end use. Total circuit miles of EHV lines with a voltage greater than 250 KV grew from 62 miles of AC EHV lines in 1952 to 67,418 miles OTA FINAL SITING REPORT Page 4 JAMES S. CANNON ,, '( (
PAGE 72
of EHV AC lines and 1745 miles of EHV DC lines in 1984.1 By the end of 1986, the figures stood at 71,629 AC miles and 2293 DC miles, with an additional 8,775 miles of EHV lines scheduled for completion by 1996.2 As technology continues to evolve, higher voltage transmission lines are being built. More than 2,000 miles of AC lines with a 765 KV capacity now exist as well as about 1,300 miles of 500 ri direct current lines.3 The expansion in the grid of long distance, high-voltage transmission lines has permitted increased short-term sales of large quantities of electricity from one electric utility to another. These transactions, called economy sales, represent a broadening of the historical pattern of each utility generating power solely for customers within its franchised service area or for sale to another utility on a long-term, contract basis. Economy sales to date generally reflect a situation of unplanned excess generation capacity, but the sales could continue over the long term if new capacity is designed specifically with increased economy sales in mind. Between 1976 and 1983 power sales among utilities grew 671 faster than sales to the ultimate end users of electricity, for example residential and conunercial customers. By 1983, the sales of power among utilities had grown to a $43 billion annual business.4 Interutility sales, which accounted for just 5.61 of total generation in 1953, constituted 20.11 in 1983.s By 1986, OTA FINAL SITING REPORT Page 5 JAMES S. CANNON
PAGE 73
at least 141 of generated electricity crossed at least one state border between the points of production and use.6 Economic and other considerations have convinced a number of utilities to build new EHV power lines to take fuller advantage of long distance transmission capability facilitated by extra high voltage technology. Por example, EHV lines reduce electricity losses which can consume up to 101 of generated electricity, thereby improving the economics of long distance transmission compared to transmission over lower voltage lines. Moreover, new transmission lines can improve the overall efficiency and reliability of electricity transportation which in turn can reduce transmission costs and help prevent supply interruptions caused by forced outages and power cutbacks. Changes in the cost of building power plants in recent years have also prompted the construction of transmission lines and increased electricity sales among utilities. Between 1971 and 1978, for example, the cost of building coal-fired and nuclear power station~ increased by 681 and 1421, respectively, in real (e.g. inflation-adjusted) dollarse7 Partly as a result of increases in power plant construction costs, electricity costs across the nation rose an average of 1751 between 1970 and 1980, with prices in many areas jumping by 2501.8 If long distance transmission capability exists, utilities OTA FINAL SITING REPORT Page 6 JAMES S. CANNON e (c 1
PAGE 74
with excess generating capacity in the form of older and generally cheaper power plants are able to offer relatively inexpensive electricity for sale to other utilities. For the utility with excess generation capacity, long distance power sales offer a source of income to offset fixed costs. Utilities purchasing power can reduce their operating expenses, avoid the construction of enormously expensive power plants and skirt the uncertainties about what the future holds for construction cost~, pollution control requirements, and the emergence of new power generation technologies. Changes in the cost of fuels, like shifts in power plant capital costs, have further helped to create regions of relatively low and high electricity prices throughout the country and to promote long distance power transmission. The prices of fuel oil and natural gas in particular have increased dramatically since 1973 relative to coal and uranium fuel, recent oil and gas price decreases notwithstanding, thereby adding to the cost of generating power at many existing plants. According to a study by the National Coal Council, the difference in the fuel price component of the cost of electricity generated in New Jersey and Pennsylvania was 8.6 cents/million BTUa of fuel input in 1965; by 1984 the differential was 78.8 cents/MMBtu. In 1965, fuel for electricity generated in California was slightly cheaper than fuel in neighboring Nevada; by 1984, Nevada fuel cost on the average 159.3 cents/MMBtu less than fuel in California.9 OTA FINAL SITING REPORT Page 7 JAMES S. CANNON r, l; I
PAGE 75
The National Coal Council further estimates that over 20 million tons of new coal production was being poured into power boilers in 1984, largely in the Midwest, to generate power to replace 85 million barrels of oil previously consumed at oilf ired units, frequently in the Northeast.1 0 By way of example of this "oil-back-out", in New Jersey, oil consumption at six large power plants dropped from 12. 2 million barrels in 1978 to just 3.6 million barrels in 1982.ll To replace the power generated by this oil, New Jersey utility companies increasingly purchased electricity produced largely from coal-burning power plants located in other states. Power imports to New Jersey from grew from no imports in 1966 to over 501 of the state's total electricity demand in 1981.12 EHV transmission is an increasingly important factor shaping new power supply strategies as well as affecting generation and use patterns from existing power plants. Long distance transmission capability ~an, for example, encourage the construction of power plants in areas with low construction costs or fewer environmental restrictions. By sizing power plant~ to supply several utilities demand throughout a large region, such strategies can also take advantage of economies of scale in construction. Furthermore, as explained above, importing power from another region can delay or eliminate the need to build some power plants altogether. OTA PINAL SITING REPORT Page 8 JAMES S. CANNON I 7 ( I
PAGE 76
Long distance interregional electricity transmission can also help define and mold national energy or environmental policies. For example, the reduction in use of oil-fired power plants in the Northeast during the past decade has reduced local air pollution levels. The increased reliance on electric! ty imported from the Midwest as a substitute source of power, however, could contribute to the formation of acid rain. One study has calculated that over 2.3 million tons of sulfur dioxide air pollution, some 131 of the utility industry's total SO2 pollution, resulted in 1984 from the generation of electricity bound for export to end users in power importing states.1 3 Future acid rain control programs could affect the patterns of long distance electrical transmission and vice versa. THE TRANSMISSION BOTTLENECK Access to EHV transmission, therefore, is one of the keys to increased power sales among utilities which in turn frequently offers utilities an opportunity to decrease electricity costs, improve reliability in power delivery to end users, and attain a number of other attractive goals. A problem, however, is encountered wherever the existing EHV transmission system is inadequate to meet the demand for long distance transmission service and when obstacles are encountered to the construction of new transmission facilities. These conditions are frequently OTA FINAL SITING REPORT Page 9 JAMES S. CANNON // ), / / I
PAGE 77
being encountered today. Transmission capacity is increasingly being stretched to the limit in some regions of the country where growth in the transmission system has been unable to keep pace with sprouting interutility sales. According to a 1985 study by the North American Electric Reliability Council, existing transmission corridors between the Midwest and the Bast were loaded to 971 of capacity in 1983 and 1984, while capacity utilization in the Pacific Northwest ran 831 in 1983 and 921 in 1984.14 Transmission line reserve margins could decrease further if the rate of power line construction declines as it has over the past two decades. About 29,000 miles of new transmission lines built between 1975 and 1984" compared to 34,000 miles which were constructed between 1965 and 1974. Por the decade 1985-1994, only 15,000 miles are expected to be completed.1 5 Many factors contribute to this decline in the pace of transmission line construction, including lower electrical demand forecasts and competing financial obligations of some utilities, but the impact eventually will be to constrain long distance power transmission capability. Complicating the issue of increased demands for long distance transmission capacity are technical constraints on utilizing existing transmission lines. Historically, the design of transmission lines by a utility closely followed projected OTA FINAL SITING REPORT Page 10 JAMES S. CANNON ,, ~> I
PAGE 78
patterns of developing demand within the company's franchised service area. Utility specific "mini-grids" of low voltage power lines were adequate to assure the flow of electricity from any of a number of power plants to all locations within the utility's service area. The direction of power flow at any moment could depend on the particular generating plant then in operation. However, sustained unidirectional flows of high volumes of electricity can over stress these electr.tcal grids leading to service cutbacks and forced outages. Many organizations which have examined the adequacy of the nation's transmission systems in recent years have come to a conclusion that impediments to the expansion of EHV transmission lines threaten to undercut the long-term reliability of the electricity grid or could hamper the delivery of low-cost electricity via interutility sales. Pour examples follow. o The North American Electric Reliability Council observed in a 1985 study that "The transmission systems continue to be heavily loaded a high percentage of the time .. Building more transmission lines would increase the capacity to transfer economy energy and, at the same time, increase the capability to respond to emergencies. However, there are impediments and disincentives to planning, licensing, and constructing new lines."1 6 OTA PINAL SITING REPORT Page 11 JAMES S. CANNON .. ) ( / I '!
PAGE 79
o In 1986 the National Governor's Association created the Committee on Energy and Environment Task Force on Electricity Transmission because "While the Governors believe our transmission system is currently technologically adequate and reliable, they (the Governors) incapable have expressed concern that it could be of supporting an increased level of economical power transactions in regional and national markets. "17 That Task Poree published a report in 1987, entitled Moving Power: Flexibility for the Future. which identified a number of impediments to power transfers. o The National Regulatory Research Institute, the research arm of the National Association of Regulatory Utility Commissioners, took up the transmission issue in its September 1987 study, Non-technical Impediments to Power Transfers. The study noted that "There is general agreement among utilities, wholesale customers and others that (transmission line) siting and licensing problems are among the moat significant barriers to expanded bulk power transfers.1118 o Finally, the National Coal Council reviewed the EHV transmission system in this country in 1986 and OTA FINAL SITING REPORT Page 12 JAMES S. CANNON
PAGE 80
concluded that "Por the next decade, the addition of new EHV transmission will not be keeping pace with the anticipated growth in electrical demand Impediments have been accumulating since the mid-1970s and, by now, are beginning to have a profound effect on the electric utility industry's ability to undertake new major transmission line construction."19 SITING PROCEDURES Impediments to the siting of transmission lines generally arise as competing interests group interact within the context of the institutional and regulatory framework for power line siting. This section provides an overview of transmission line siting procedures starting with the long range energy planning process through which states and utilities strive to identify future electricity supply requirements. Once a need for new power supplies has been identified, specific transmission line projects are designed by utilities and approval for those projects is sought from state agencies charged with certification and licensing. Moreover, project approvals from a variety of local governmental entities are usually required. In addition to these state and local siting procedures, this section also discusses special siting requirements for power lines crossing federal and tribal lands and for multi-state transmission line projects. OTA FINAL SITING REPORT Page 13 JAMES S. CANNON .~--, I ... ,, y
PAGE 81
Capacity Planning Recognition of the need for new transmission lines usually surfaces through long range energy planning processes which attempt to predict electricity demand patterns in future years and decades. At least 31 states require electric utilities to file long range supply and demand plans for their service areas. 20 These plans discuss, among other issues r anticipated electricity supply and demand, the need for new power generation or transmission facilities, and the role expected to be played in the supply and demand picture by nonconventional or nonutility generated power. Moreover, utilities are required to submit planning analyses to support their applications for approval of specific power generation or transmission projects. Long range energy plans generally reflect a 20-year planning horizon, although shorter-range planning frameworks of 10 to 15 years are not uncommon. In many cases, utility plans are supplemented by energy planning efforts made by state government agencies. A recent survey of state electricity regulatory programs analyzed by the West Virginia Public Service Commission (hereafter referred to as the West Virginia PSC survey) identified 15 states where public utility commissions performed independent electricity plans and 11 states where planning was performed by a state energy office or department. 21 However, laws in only a few states, such as California, New Jersey, and New York, require agencies to solicit OTA FINAL SITING REPORT Page 14 JAMES S. CANNON ..... 'I )
PAGE 82
public comment during the planning process and to publish state energy plans at periodic intervals. Several factors undercut the effectiveness of energy planning process-ea in creating the technical rationale to support new long distance EHV transmission lines, especially if those lines connect different utility service areas in different states. First, many state energy regulatory agencies do not have adequate staff either to scrutinize utility long range plans or to prepare detailed energy forecasts on their own. Thus planning reports often receive close review by a state agency only in the context of a review of a specific construction project proposed years after the need for the project was first identified, but not critically studied at the time, in a long range plan. Secondly, separate long range plans are normally submitted to regulatory agencies by individual utility companies and each plan discusses only the portions of energy projects directly affecting that utility, although the utilities themselves collaborate on joint project plans. Most state-mandated long range planning programs do not require utilities jointly involved in the development of a transmission line to coordinate their planning reports with regard to that project. The task of consolidating the individual plans into a comprehensive picture of a state's electricity system, eliminating overlap and filling in the blanks where necessary, often falls to the limited OTA FINAL SITING REPORT Page 15
PAGE 83
resources of the state agency to which the plans are submitted. In the same vein, since utilities' plans tend to focus on supply and demand issues within their respective service areas, issues related to power purchases from other utilities, including the construction of transmission lines to facilitate interutility sales, are not necessarily addressed in detail in long range plans. Traditionally, the isue of the need for new power plants within a utility's service area is the central question addressed in long range planning and it overshadows transmission and interutility sales issues. Thus the National Governor's Association report noted that ... determinations of transmission requirements are frequently ancillary or iterative to, rather than integral to the determination of need for new generating capacity."22 Identification of the overall efficiency or economic benefits potentially obtainable from expansion of the EHV transmission line system and increased interutility sales can easily go unrecognized in the planning process. state certification and Licensing Major transmission line construction projects require some sort of state certification and/or licensing. Certification normally comes in the form of the issuance of a "Certificate of Public Convenience and Necessity" ( CCN) by a state's public utility commission (PUC). Other state agencies, such as the environmental protection department, are also involved in the OTA FINAL SITING REPORT Page 16 JAMES S. CANNON .. I {I I .i
PAGE 84
licensing of projects through, for example, their responsibility to issue requisite construction and operating permits. In some states, power project siting boards coordinate state agency responses to transmission line projects as well as serve as decisionmaking entities. A CCN is a prerequisite in many cases for other permits and authorizations, such as eminent domain power, which might be needed for the completion of the project. From the perspective of the public utility commission staff reviewing a transmission line CCN application, three basic concerns are usually analyzed in detail. They are the demonstration of need for the project by the applying utility, the pot1 ntial public benefits and costs of the project, and. environmental and public heal th considerations Of the three, the need for more transmission capability is generally the most significant issue. Requirements for documentation in support of a CCN application are vague in most states, which creates one of the many sources of uncertainty in the certification process. Applications usually include formal testimony by the utility swmnarizing the utility's argument for the project. Upon receipt of an application, a case or docket is opened by the PUC, a hearing schedule is established and potential interveners are notified. Interveners frequently include other state agencies and utilities large power users, and public interest groups OTA FINAL SITING REPORT Page 17 JAMES S. CANNON
PAGE 85
The PUC either accepts or rejects interveners' applications and the case usually enters a "discovery" phase during which the various parties collect and study information about the project obtained through depositions and other methods of information exchange. At the conclusion of the discovery phase, the PUC staff and the interveners file their formal testimony, including the testimony of expert witnesses, and the utility files a second, or rebuttal, testimony. The case next enters the hearing phase during which the presenters of testimony submit to examination and cross examination by attorneys for all parties. Hearings are frequently adjudicated by a hearing examiner appointed by the PUC commissioners, although they are sometimes held in front of the commissioners themselves. Most states also require that public meetings be held to solicit public opinion on the project. In some other states public meetings can be called at the discretion of the public service connnission.23 In instances where a hearing examiner is utilized, he or she prepares a report and a proposed or reconunended decision which is reviewed and upheld, rejected or modified by the PUC commissioners. If the commissioners hear the case, they prepare both the report and render the final judgement. are usually appealable to the state court system. OTA FINAL SITING REPORT Page 18 PUC decisions JAMES S. CANNON
PAGE 86
The West Virginia PSC survey found that the certification process in most states generally takes less than a year, although the process can take years in some cases ( see for example the Washington Loop Project case study below). In none of the states responding to the survey is a limit placed on the amount of time a public service commission can take to decide on a CCN application.24 Depending on the state, a utility can proceed to obtain permits from other state agencies needed to construct a transmission line either before, during or after a CCN is granted. In 11 of 33 states responding to the West Virginia PSC survey, utilities are not permitted to pursue required permits from other state agencies until a final ruling on a CCN has been rendered.2 5 In at least 18 states a j-oint certification and siting approval process has been instituted which can simplify and expedite state agency permitting issuance. At least 14 states have established some sort of a siting board to coordinate and resolve permitting issuea.26 Even with all required state agency permits in hand, a transmission line can not be constructed until rights-of-way have been acquired for the land through which the line travels. For some projects, land acquisition for the transmission line corridor can not be obtained voluntarily by the utility through negotiation with the land owner. Such opposition can result in OTA FINAL SITING REPORT Page 19 JAMES S. CANNON c, (' }--. l_,,i -
PAGE 87
the abandonment of a project or a costly rerouting unless the utility can exert a power of eminent domain to acquire the needed property upon payment of a court-approved level of compensation. In a few states, utilities are granted the power of eminent domain by state law for any transmission line project, but in most the issuance of a CCN is a prerequisite before eminent domain powers can be exercised. According to the West Virginia PSC survey, in at least 11 states the issue of whether not eminent domain powers are granted to a utility is decided as one component of the certification and siting process. At least 17 states require a separate application and decisionmaking process for eminent domain which occurs after siting approval has been obtained. 2 7 In some states, the power of eminent domain is obtained from a court which considers issuance of a CCN and siting approval as evidence in its decisionmaking process.28 Local Permits and Approvals Special use permits and zoning variances issued by local and county governments are conunonly required before construction of a transmission line project can begin. Acquisition of local permits can be an extremely complex and time-consuming undertaking, especially in areas where significant local opposition to a transmission line project exists. A recent case study by the National Coal Council of a 50 nu.le transmission line project found that over 30 local and county governments had to be OTA FINAL SITING REPORT Page 20 JAMES S. CANNON (7 J. G )
PAGE 88
individually contacted regarding the project.29 For a long distance interstate transmission line project, separate approvals from literally hundreds of local government entities can be required. Each decisionmaking process generally includes an appeal process through the court system in addition to the administrative review process. Several states grant, as part of their certification and licensing processes, the authority of one agency to override the decisions of other agencies, including local governments. At least 17 states grant such powers,30 but in at least 12 states, local agencies have the authority to block tral'J.Smission line projects from being built within their jurisdiction.31 Permitting Transmission Lines Across Federal Lands Long distance transmission lines frequently cross lands administered by federal agencies, especially in the western United States. In most cases, siting a line on federal lands requires a right-of-way from the Gdministering agency in a process separate and distinct from state and local agency actions. Federal land permitting frequently involves three steps; an environmental review, a land use planning process, and a review of a specific right-of-way application. Under Section 102(2) (c) the National Environmental Policy Act of 1969 (NEPA), an Environmental Impact Statement (EIS) must OTA FINAL SITING REPORT Page 21 JAMES S. CANNON
PAGE 89
be prepared prior to any major federal action significantly affecting the quality of the human environment. Most major transmission line projects that cross long stretches of federal lands fall under the EIS requirement. The EIS process begins with a preliminary analysis which is aimed at determining how extensive an environmental review is required by NEPA for a particular project. A "finding of no significant impact" can permit a project approval process to continue without more analysis under NEPA. If minor impacts are anticipated, an abbreviated environmental assessment is deemed adequate. For projects with significant potential impacts, a full EIS is required to be prepared by the agency administering the land affected by the transmission line. In cases where multiple categories of federal lands are involved, a lead agency is selected, but all agencies participate in and are bound by the results of the EIS. For example, for the 1984 EIS analyzing the 345 KV line between the San Juan Generating Station in New Mexico and Rifle, Colorado, the Rural Electrification Administration acted as the lead agency and the Forest Service ( USFS) the Bureau of Land Management ( BLM) and the Western Area Power Administration served as cooperating agencies.32 The first step in the EIS process is a "scoping" effort OTA FINAL SITING REPORT Page 22 JAMES S. CANNON ( 1 I ',
PAGE 90
during which important environmental issues raised by a proposed project are identified, in part through a solicitation of public opinion. process. This is followed by the actual environmental analysis Under NEPA, alternatives to the proposed process must also be identified and studied, including a "no-action" al1ernative of not proceeding with the project in any form. This stage of the process concludes with the publication of a Draft EIS which is followed by a public comment period. The comments are reviewed, revisions to the draft are made, and a Final EIS is published, which includes responses to public comments. The agency preparing the EIS then issues a Notice of Decision endorsing one or more of the project alternatives discussed in the EIS as the "proposed" or "preferred" option. EIS'a and Notices of Decision can be appealed first to the Director of the lead agency and then to the federal court system, starting with a U.S. District Court. Separate from the NEPA process, several federal agencies, notably the Bureau of Land Management and the U.S. Forest Service are required to perform comprehensive land use plans for the lands under their jurisdiction and to identify areas suitable for the construction of transmission lines. Land use plans, called Resource Management Plans, for public domain lands under control of the BLM are required under the Federal Land Policy and Management Act of 1976. Similarly, National Forest land use plans are required under the National Forest Management Act of OTA FINAL SITING REPORT Page 23 JAMES S. CANNON (r' I / \ >() I
PAGE 91
1976. Utility corridors are frequently discussed in Regional Guides, which are prepared for each of the USFS' s ten regions, and in the Land and Resource Management Plans for each National Forest. Identification of potential utility line corridors is an important part of these land use plans because only projects sited along corridors identified as suitable for transmission lines in the plans can be approved. Many land use plans, such as the recently released Farmington Resource Management Plan for the BLM administered lands in the San Juan Basin in New Mexico, employ a "window" approach to planning for transmission lines which seeks to identify general areas where power lines might be needed and more specific areas where a conflicting land use would preempt transmission line construction. This approach provides significantly more flexibility in later line siting efforts than would exist if only specific corridor paths were approved at the land use planning stage. Apart from the NEPA and land use planning processes, approval of the use of federal lands for a specific transmission line is still required from the administering federal agency. Depending on the type of transmission line project and the categories of federal lands involved, a number of federal agency permits might be required. For example, the BLM issues a RightOf-Way permit across public lands and the USFS issues an OTA FINAL SITING REPORT Page 24 JAMES S. CANNON (
PAGE 92
Authorizing Document for a line to cross a National Forest. For lines crossing an international boundary, a permit must be obtained from the Department of Energy as the implementing agency of a 1953 Presidential Executive Order af acting international electricity transactions. The Department of Defense can deny a permit if it interferes with a major military installation or if it is deemed to interfere witn national security. The Federal Highway Administration must approve corridor paths along interstate highways, which is currently only done as an exception to FHA policy. Corps of Engineer permits must be obtained for lines crossing interstate navigable waterways. The Federal Energy Regulatory Commission must approve transmission line projects associated with federal hydroelectric facilitiea.33 Permitting Transmission Lines Across Tribal Lands Approval of transmission line corridors across tribal lands must be obtained from the governing Tribal Council or other tribal ruling body for the affected lands. There is no federal requirement for land use planning on tribal lands, nor are there standardized procedures for applying for a right-of-way across tribal lands. Reporting requirements and the decisionmaking process employed to rule on the application vary among different tribal governments and can change markedly over ti~e. Utility companies cannot exercise the power of eminent domain on tribal lands regardless of whatever approvals of OTA FINAL SITING REPORT Page 25 JAMES S. CANNON i \J-:y (._
PAGE 93
transmission line projects have been made by federal or state agencies. In eight states, tribal governments are consulted as part of the state process for transmission line certification and licensing even if tribal lands are not involved.34 Siting of transmission line on tribal lands has proven to be very difficult in some instances, even when only sparsely populated lands are involved. Por example, proposed. transmission line rights-of-way from the San Juan power plant in New Mexico across the Navajo Nation where the transmission system can be linked to the electricity demand centers in the Far West have been debated by the Navajo Tribal Council literally for decades and remain a very controversial topic with no clear resolution in site. Regardless of the decisionmaking procedure used by the tribal government, any action taken .by a tribal government must also be approved by the U.S. Bureau of Indian Affairs (BIA), as the federal trustee for tribal lands. Because BIA approval of a permit for a large transmission line project is often ruled to be a major federal action under NEPA, Environment Impact Statements can be required for projects on tribal lands. For example, the BIA has acted as lead agency for the EIS for the proposed Ole power line in New Mexico because several proposed routes could affect Pueblo Indian lands or sacred sites within a National Forest (see Ole Project case study below). OTA FINAL SITING REPORT Page 26 JAMES S CANNON
PAGE 94
Kulti-state Siting Efforts Certification and siting of transmission lines is generally the responsibility of the state regulatory agencies which have jurisdiction over the utilities proposing the project or the land traversed by the power line. For a long distance power line across several states, regulatory agencies in each state independently consider the portion of the project within their jurisdiction. Denial of a CCN in any one state can lead to the abandonment of an entire interstate project. An interstate transmission line project which distributes costs and benefits in many states presents a difficult problem for state regulatory agencies as they assess the overall need for the project in relation to the traditional state-specific criteria for certification. Only a few programs have been undertaken to date to bring regulatory a~encies togethe during the planning or permitting of an interstate power line. Conununication among states most frequently occurs on an informal basis through associations of state agencies such as the National Association of Regulatory Utility CoDDDissioners (NARUC). Other examples include: the Western Interstate Energy Board and the Western ConfereLce of Public Service Commissioners, which in 1987 established a joint Committee ~n Regional Electric Power Cooperation; the National Go-~rnors Association, which has formed a CollDllittee on Energy and Environment Task Poree on Electricity OTA FINAL SITING REPORT Page 27 JAMES S CANNON I I ._ j :,J
PAGE 95
Transmission; and the New England Governors' Conference, which has formed an interstate agency Power Planning Conunittee. Occasionally regulators from other states will be invited to observe or participate in a planning or certification process taking place in another state. Sometimes a state agency will take the initiative to intervene in a regulatory proceeding in another state. The federal government currently plays only a small role in transmission line certification issues for interstate or interutility projects. Under the Federal Power Act, the Federal Energy Regulatory Conunission (FERC) has the authority to set the wholesale rates which utilities may charge for bulk or economy sales. Although FERC decisions are critical in determining the overall economic viability of a long distance power line project, the agency itself does little to assist in power line siting. Utility companies themselves have done the most to foster interutili ty planning for reliability purposes, including the identification of the need for new long distance transmission capacity. One agency that performs this function as part of its mandate is the North American Electric Reliability Council. The Council and its nine regional constituent councils were created to promote reliability in electricity supply. In pursuit of this objective it often undertakes studies of methods to facilitate interutility power sales. OTA FINAL SITING REPORT Page 28 JAMES S. CANNON
PAGE 96
Power pools of utility companies, of which about 30 currently exist in the United States, provide another forum for joint utility planning and transmission line project development. The New England Power Pool and the P~nnsylvania-Jersey-Maryland Power Pool are examples of such organizations of utility companies. Some large utility holding companies, such as the American Electric Power Corporation, prepare a single long range electric! ty plan for all of its subsidiary utility companies. Moreover, ad hoc interutili ty agreement.J occur frequently among utility companies. For example, the Mid-American Interconnected Network (MAIN) agreement establishes "Transmission Loading Relief Procedures" to set power delivery schedules if overloading of a transmission line occurs in one utility's service area as a result of a sales transfer between two other utilities.35 With one exception, multi-state utility a.nd state agency programs regarding long distance t~ansacticns are voluntary. The one mandated interstate electricity planning agency the Northwest Power Planning Council (NPPC) -has been established and is guided by federal legislation. 36 Washington, Oregon, Idaho and Montana are the member states of NPPC, which was created by the Pacific Northwest Electric Power and Conservation Act of 1980. The Council prepare9 long range electricity demand forecasts for the region and develops power supply plans capable of meeting that demand.37 OTA FINAL SITING REPORT Page 29 JAMES S. CANNON ) I
PAGE 97
IMPEDIMENTS TO TRANSMISSION LINE SITING Institutional, regulatory, and legal elements of the process for siting transmission lines, from long range capacity planning through the exercise of eminent domain and construction, can delay EHV power line projects by adding to their completion time and cost and by contributing to the uncertainty that the required approvals will be obtained. Three sources of impediments are discussed in this section; power line approval procedures, jurisdi~tional complexities among agencies required to give approval to a project, and the lack of multi-state coordination. Obstacles to Transmission Line Approval Approval for a transmission line project in one sense begins with the long range planning process years before an application for a specific project is filed. State-mandated planning processes tend to have a strong focus on the need for new power plants and frequently do not analyze in depth the potential for increased long distance interutility transmission to facilitate interutility sales as a supply option. The inherent uncertainties involved in interutili ty power sales, especially from another state or from Can~da, often result in a low ranking of this option in long range plans, and hence little discussion of interutility sales among supply alternatives in planning documents. Other shortcomings of the long range planning process OTA FINAL SITING REPORT Page 30 JAMES S. CANNON (' ; ',/' )
PAGE 98
are that plans are usually required for individual utilities even though some transmission line projects are jointly sponsored, they are not required to discuss components of projects owned by other utilities or located out of state, and they are reviewed by a state agency staff that does not necessarily have the in-house expertise or resources to thoroughly scrutinize them. The same shortcomings often apply to long range electricity plans produced directly by state regulatory agencies. The lack of attention given to long distance transmission projects and interutility sales during the long range planning process stands in sharp contrast to the attention the issue draws in the world of actual electricity sales contracts and transmission line project development. Yet, when the time comes for decisions about specific projects and contracts, limited analysis of the complex issues involved is available from past planning efforts. State laws regarding the obligations of utilities and utility regulators alike often create obstacles to long distance transmission line projects. State utility franchise laws generally place the highest obligation on a utility to provide reliable service within its service area. This provides a disincentive for a utility to consider a project such as building a power plant or transmission line which may have as its goal supplying electricity to customers of another utility. This OTA FINAL SITING REPORT Page 31 JAMES S. CANNON
PAGE 99
argument has been summarized by the National Regulatory Research Institute as follows: "The franchise system, on the other hand, may be a major problem because it is an expression of the natural monopoly concept. Among other things, in return for an exclusive service territory, the latter means the utility must provide all comers with service at all times. It will, there ore, attempt to size its system to meet its expected demand, and will strive to be selfsufficient in terms of supply in order to assure its ability to provide service At the same time, the utility is legally forbidden to look for new customers outside its area. As a result, under normal circumstances, it will generally have minimal need for purchased capacity, and will have little available to sell to othera."38 State regulatory agency transmission line siting criteria reflect the same specificity with regard to service areas that guide most utility company actions. In assessing need for a transmission line, state public service commissions generally look first to the benefits to the customers of the utility O'l'A PINAL SITING REPORT Page 32 JAMES S. CANNON
PAGE 100
proposing to build the line. These benefits are then balanced against the anticipated coats o! the project, including impacts on the environment, the lifestyles of affected residents and other public interest considerations. A difficult analytical dilemma is frequently encountered by state regulatory agencies facing an application for a long distance transmission line project. Often the only direct benefit to the customers living in the service area through which a transmission line passes is improved reliability of electricity supply, which is impossible to quantify. The quantifiable benefits of low coat electricity often accrue to customers living in other service areas or states outside of the agencies jurisdiction or the scope of the application. On the other hand, the local coats are readily obvious and in many cases quantifiable, including exposure of people to high voltage electrical fields, lifestyle and economic disruption, and aesthetic, environmental, and recreational impacts. Thia situation complicates the balancing process for state regulatory agencies, especially in states, such as Wisconsin, which have laws which require that local or statewide benefits outweigh local coats as a condition of power line approval 3 9 Many state regulatory agencies have responded by developing conservative "prudency" or "public interest" criteria against which to judge the merits of utility projects under review which OTA FINAL SITING REPORT Page 33 JAMES S. CANNON ff,
PAGE 101
have on occasion been criticized as "highly parochial attitudes" that dampen the enthusiasm for utilities to undertake long distance transmission line projects.40 Another problem utility coapany applicants face is that power line approval criteria can differ among agencies especially when agencies are located in different states. As a result, power companies often must file multiple applications in support of a transmission line project. Moreover, the information in each application must tailor fit the evaluation criteria of the agency to which it is submitted. Unless one agency is empowered to veto a contrary decision by another agency, a utility ,applicant faces several "showstopper" regulatory review processes. An adverse decision in any one arena in a.ny state can force the abandonment of the entire project. Moreover, criteria used by a single agency can change, even during the process of review of one project. As noted by the National Coal Council: "a strong endorsement of a major power supply project by a regulatory commission at one point in time does not provide any real assurance that the same regulatory commission (with, perhaps, a different membership) would not oppose the continuation and completion of that very project at a later point in time."41 OTA FINAL SITING REPORT Page 34 JAMES S CANNON
PAGE 102
A final consideration is that very few siting procedures contain any deadlines for decisionmaking. Thus, it becomes impossible to predict with confidence when a power line project approval or denial will be forthcoming. Thia too adds to the uncertainty underpinning long distance transmission line projects which require approval f roa dozens of agencies Bven when deadlines are eatablished, they usually affect only a component of the decisionmalcing process, not the entire process. For example, schedules set for regulatory agency actions are completely distinct from the schedules set by courts to which judicial challenges to those actions are addressed. Scheduling problems encountered by transmission line projects have led the National Governors Aaaociation (NGA) to conclude that "the lack of a definitive time table for the regulatory process appears to be one of the biggest causes for delay."42 Jurisdictional complexities A labyrinth of regulatory agency requirements face the sponsors of long distance transmission line projects, involving federal, state, and local agencies and courts. Coordination among agencies is frequently poor and jurisdictional boundaries are often vague, leading sometimes to mismatches, overlaps, and gapa in agency responsibilities and to interagency conflicts. Federal and tribal land administering agencies have OTA FINAL SITING REPORT Page 35 JAMES S. CANNON
PAGE 103
permitting powers which exist separate from state regulatory agency approval procedures. Decisions by these agencies bear on the viability of a transmission line project regardless of state agency actions. Federal and state jurisdictions mesh somewhat more closely between the Pederal Blectric Regulatory Commission (PBRC), which sets wholesale power rates upon which interutility sales depend, and state public utility commissions, which usually grant required project licenses. However, according to the National Regulatory Research Institute, "there is virtually no coordination between the two entities in regard to these activities."43 Depending on the state, a number of state regulatory agencies are involved in the perm! tting process for a large transmission line project. Although many states have established either a Siting Board or appointed a lead agency to coordinate the state review process, guiding an application through the regulatory apparatus can be a difficult and time consuming task. Joint agency permitting processes remain the exception, not the rule, and because consideration of some permits is often contingent on issuance of others, agency approvals must sometimes be sought sequentially rather than simultaneously. Participation of a multitude of local municipalities and county governments in permitting a long distance transmission line represents another layer of juriadictional complexity. Even OTA PINAL SITING REPORT Page 36 JAMBS S. CANNON 9?
PAGE 104
in states where local decisions can be overruled by a state siting agency, local government actions are still important to the overall siting proceaa especially where strong local opposition makes a state agency leery of vetoing local government actions. Added to this intricate network of regulatory agency interactions is the court ayat. Judicial review of regulatory agency actions is a legal right of opponents to moat agency decisions. Thus, depending on the agency and the decision involved, federal, state, and local courts frequently enter the transmission line approval process and can create lengthy tangents from the regulatory agency review process. Lack of Multi-state coordination Variations in transmiaaion line approval processes among states coupled with the lack of coordination in decisionmaking and interstate information exchange can create major obstacles to long distance power line projects. Governors Aaaociation1 As noted by the National "differences in both state siting and certification procedures and in the regulatory process itself may frustrate efforts to develop multi-state lines even when those lines would be acceptable to each of the states involved."44 OTA FINAL SITING REPORT Page 37 JAMES S. CANNON
PAGE 105
Bven where there is some fledgling effort at inter-state coordination, no one state agency is necessarily bound to implement a decision made as a reeul t of multi-state planning effort. Coordination between state agencies and the FERC is also incomplete. The current practice of independent actions by PIRC and by state regulatory agencies has moved the Rational Regulatory Research Institute to conclude that "the federal-state regulatory dichotomy can be considered to be an important institutional impediment to the movement of bulk power between utilities."4 5 One problem that can result from the lack of coordination between FERC and state agencies is that state public utility commissions, as they make their cost/benefit analyses, cannot necessarily obtain from FERC information they need about whether interutility sales from a long distance transmission line will be economical and provide system wide benefits. Another potential problem is that state regulatory decisions with regard to interutility power projects can be affected by future FBRC rulings which the agencies cannot anticipate and over which they have no control. IN'l'BRBST GROUP PBRSPICTIVES OTA FINAL SITING REPORT Page 38 JAMES S. CANNON /o/
PAGE 106
A number of interest groupa frequently interact during the siting of a transmission line. Although the positions of these groups are molded by the individual circwutancea surrounding each project, a number of perspectives are commonly associated with each group. It ia the clash between these perspectives during the siting proceaa which frequently leads to the conflicts that impede tranamisaion line siting. Utility Companie Utilities have moved a long way from the entrenched, adversarial approach they frequently took in the paat to transmission line siting epitomized by the slogan "decide, announce, and def end" At least 35 utili tiea in the United State now have formal public participation progrmu to assist in the planning of utility projecta.4 6 Nearly all utilities include public participation at some point in their decisionmaking processes regarding transmission lines. Nonetheleaa, it is common for utility companies to feel that criticism of transmiaaion line projects comea from amateurs who cannot possibly understand the econOllli.c and technical intricacies of the electric utility industry. In many respects, utilities do know more, if not beat, and in adversarial environments resentment can build aa other interest groups "try to tell us how to do our buaineaa." Moreover, state franchise laws and OTA PINAL SITING REPORT Paga 39 JAMES S. CANNON /b~.
PAGE 107
historical utility standard operating practices tend to promote conservative, risk-averse attitudes on the part of many utility companies which on occasion can reinforce a skepticism towards auggeations originating outside utility company circles, especially ideas regarding complex projects such as interstate transmission line construction. Government Regulators State and federal government regulatory agencies respond first and foremost to the statutory mandates under which they operate. Por state public utility commissions this usually means careful implementation of prudency and coat/benefit balancing concepts in transmission line siting reviews. Por an environmental protection department this translates to assurance that transmission line applicants will comply with a wide range of construction and operating requirements. A narrow perspective can frequently develop among individual regulatory agencies with each agency focussed on fulfilling its mandated responsibilities. Thia approach doea not necessarily foster free information exchange, cooperation, and compromise of decisionmaking authority and it can undercut the development of a rationale for collaboration among agencies that could be needed to expedite and facilitate transmission line siting approval. Landowners and Affected Populations OTA PINAL SITING REPORT Page 40 JAMES S. CANNON
PAGE 108
People who live, work, or play directly under or near a proposed transmission line corridor are frequently the most vocal interest group during the siting process. Their concerns can take many forms. If they live directly beneath the proposed path of the power line, they mi9ht be oppoaed to moving or they might fear that they will be inadequately compensated for the loss of their homea. Th same concerns are typical if businesses, such aa farm or ranch operations, are ai tuated along a line' a path. Public health concerns are also cOlmllOnly encountered among people who will be exposed to the electrical field generated by an EHV transmission line. Local opposition to a transmission line can also result if the line ia perceived to threaten non-economic values attached to the land. Thus, for example, A soma Native American groups have opposed transmission lines crossing lands they hold sacred. Subtle lifestyle disruptions caused by transmission lines, such aa aesthetic degradations, can foster controversy about a project. Non-economic concerns can cauaa an affected population to view aa unfair the distribution of the economic coats and benefits of a tranamisaion line project if they believe they will absorb a disproportionate share of the coats while the benefits are more widely dispersed or accrue to others altogether. These concerns can often be addressed through careful route selection for a proposed line, extenive impact mitigation OTA FINAL SITING REPORT Page 41 JAMBS S. CANNON
PAGE 109
programs, and increased compensation to the affected population. Nevertheless, the perspective of the locally population can aolidify into nonnegotiable opposition, typified by the slogan "not in my backyard." Ratepayer consumer Groupa The electricity ratepayer is usually concerned chiefly with the coat of electricity at the point of end uaa and, to a leaser extant, with long-term reliability of supply. Under the current conditions of excess power generation capacity in many parts of the country, these concerns frequently are reflected in support of increased competition in the electric utility industry, more -interutility aalea, and wider intarutility connections to facilitate long distance transfer of cheap electricity. In some instances, however, concern over the cost of a transmission line project or over the future availability, coat, and reliability of supply can outweigh these pro-transmission expansion sentiments, leading some ratepayer organizations to oppose such projects. Bnyirompantal orqanizat10n1 Environmental groups often take strong exception to the potentially adverse impacts of long distance transmission lines on the visual and physical environment, on wildlife, and on human health and traditional lifaatylea. In many instances where proposed transmission lines cross inhabited areas, the concerns of environmental group reflect tho of local landowners, OTA FINAL SITING REPORT Page 42 JAMES S. CANNON / /fJ3
PAGE 110
particularly with regard to public health issues and the disruption of traditional lifestyles and sacred sites. Alternatively, environmental groups can oppose transmission line project because they conflict with land use objectives distinct from those held by the affected population, thereby placing them in conflict with the landowners on these issues. Por example, a proposed corridor for a transmission line might appear to environmental groups to be a poor choice of use of the land compared to competing uses as wilderness, a plant or wildlife preserve, a habitat protection zone, or as a recreation spot. Thia situation often occurs for transmission line projects proposed to cross sparsely populated lands such as National Poreats and other public lands managed by the federal government. Rerouting and impact mitigation measures can sometimes, but not always resolve satisfactorily many of these environmental concerns. Bnarqy syatama Adyocatea A number of organizations have aa their objective the promotion of a particular energy policy objective or technology. Por example, "soft path" energy advocates believe that a combination of energy programs to promote conservation and decentralized power supply systems provide the beat approach to long-term energy security in this country. 4 7 Similarly, trade organizations exist to promote individual energy technologies O'l'A PINAL SITING RBPORT Paga 43 JAMBS S. CANNON
PAGE 111
including decentralized systems, conservation, and "hard path" coal and nuclear generating technologies. In some instances promotion of long distance electricity transmission and interutility power sales can be seen as antithetical to the objectives of these organizations and they have participated in the decisionmaking process for specific transmission line projects. Por example projects involving sales of electricity from large fossil-fuel or nuclear generating stations, which are not the preferred. power supplier among either soft energy proponents or decentralized power technology supporters, have drawn opposition from energy technology advocates. Thus, in the late 1970s, the California organization Citizens for a Better Environment opposed the expansion of long distance transmission capacity to that state from the Northwest in part because of concern that the capacity would be used as a justification for the building of several large nuclear power plants then proposed for construction in Washington state and opposed by the group on technology grounds. On the other hand, in late 1987, the National Coal Association intervened in a Department of Energy proceeding in opposition to a permit to build a transmission line from Quebec, Canada to an existing utility line owned by Central Maine Power Company. The Association feared the project would promote the importation and use of hydroelectric power to the detriment of OTA PINAL SITING REPORT Page 44 JAMES S. CANNON /o7
PAGE 112
electricity produced at domestic coal-fired power plants.4 8 OPTIONS TO IMPROVE TRANSMISSION LINE SITING According to the West Virginia PSC survey, state regulatory agencies have approved 515 transmission line projects of all types within the last ten years, while denying approval for only 18. More than two-thirds of the projects approved during the last five years have been completed.4 9 Thus, the approval of transmission line projects by regulatory agencies is a routine, although difficult procedure. The success rate of power line siting not withstanding, impediments to siting continue to draw fire from interest groups and a number of recommendations for ways to improve the siting process now enjoy considerable support in some circles. Several proposed reconnnendations are presented as policy options in this section. Expanding the Planning Process Inadequacies in the long range planning process affecting electricity supply and demand, especially with regard to transmission line planning, could be reduced in a number of ways. Simply providing more resources to the agencies involved in planning could help produce more comprehensive and insightful OTA PINAL SITING REPORT Page 45 JAMES S. CANNON
PAGE 113
plans. Transmission line and interutility power sales issues could receive a higher priority in the planning process The scope of planning efforts, including those submitted by individual utility companiea, could be broadened to include regional and interstate electricity issues. Soma entities which are frequently exempted from planning requirements, such as municipal-owned utilities and power cooperatives, could be required to participate more in planning. Greater integration of planning efforts and transmission line project development could also enhance the usefulness of planning. More relevant and accurate long range electric! ty plans should be of greater usefulness during the regulatory review process of specific transmission line projects, especially with regard to the overall coats and benefits of a project. As noted by the National Governors Association, "planning on a multi-state or regional basis can help identify even larger sources of savings from improved coordination of generation and transmission capacity development."5O The Washington Utilities and Transportation Commission has been developing a new long range planning process since mid-1987 which is designed to implement several of these reconanendations. Called the Least-cost Planning and Avoided Cost project, the Commission is developing a standardized computer model using a spreadsheet format to record and analyze economic data on future OTA FINAL SITING REPORT Page 46 JAMES S CANNON
PAGE 114
electricity supply and demand. Consistent reporting requirements are being developed for each utility company required to submit long range electricity plans. The Commission hopes to merge the utility plans and to create a statewide energy resource blueprint. The inmediate objectives of the program are to improve the organization of utility-supplied data, to better predict and understand the implications of future electricity supply and demand patterns on the state, and to enhance the Commission's ability to analyze proposed power projects.Sl Improved planning should help utilities anticipate land requirements for transmission line corridors farther in advance and with greater certainty of actual future need. This has led the National Governor's Association and others to suggest that several transmission line corridors be pre-approved as part of the planning process. Creation of "resource banks" of approved corridors could provide "a bridge between the planning and transmission line certification processes to reduce the lead time for final approval" of transmission line projects, the NGA believes.52 On the other hand, it can be argued that preselection of multiple corridors, some of which will never be used for transmission lines, can needlessly involve and upset people, lead to unnecessary changes in patterns of land use and value, and add significantly to the coat of planning.53 streamlining the Regulatory Approval Process OTA PINAL SITING REPORT Page 47 JAMES S. CANNON
PAGE 115
Simplifying and shortening the process for obtaining certification and license approvals for a transmission line project from state and local regulatory agencies has undoubtedly been the single largest target of reformers of the siting process for years. Frustration with the difficulties inherent in the current system has in part prompted the Electric Power Research Institute to develop a handbook for utilities to use as it weaves through the regulatory labyrinth, entitled optimistically A streamlined Procedure for Obtaining Regulatory Approval for Hew Transmission Linea.54 One of the moat frequently enunciated suggestions is that the siting process in a state be coordinated by a single agency or by a Si ting Board c011p0aed of members of several agencies This step has already been taken in about 12 states, although the circumstances when the Boards become involved and with what powers varies conaiderably.55 Thia move toward "one-atop" shopping for licenses and perm! ts has in fact expedited the siting process in many cases, but, as the Coal Creek Project case study presented below shows, it provides no guarantee that controversy surrounding a transmission line project can be resolved. Nonetheless, the National Governors Association has concluded that "consolidation of the approval process within a single agency (even if that agency must work with other agencies) appears to improve the predictability and certainty of the regulatory process, and may increase the speed with which the O'l'A PINAL SITING REPORT Page 48 JAMES S CANNON Ill
PAGE 116
state acts on project proposals."56 Endowing siting agencies or boards with the power to overrule decisions made by other regulatory agencies and local governments is another suggestion commonly offered to speed government review of transmission line project applications. Many state programa currently do authorize preemption of deciaionmaking authority by some agencies, and this has resulted in some instances in faster ai ting of transmission lines. But delays can still occur in part because of a reluctance to assert veto authority and in part because it is the decision of another agency that can be preempted and not the right of that agency to conduct its review process. Thus, endowing an agency with veto power may save little time and effort in the review process, but it does create a greater degree of certainty over the final outcome. Establishment of clear criteria against which a transmission line application can be measured could also help simplify the siting process. Some states, including Florida and Montana, have established specific siting criteria, such as minimum corridor widths for power lines, baaed on generic issues, such as public health concerns. Greater definitiveness and specificity in siting criteria can ease the information requirements for the applying utilities and help focus the review process. OTA PINAL SITING REPORT Page 49 JAMES S. CANNON I I)--
PAGE 117
Finally, many critics of transmission line siting procedures call for the institution of firm deadlines in decisionmaking. The NGA has noted that "of those (impediments) involving state regulation, lack of a definitive time table for the regulatory process appears to be one of the biggest causes of delay."57 On the other hand, the price tag for forcing decisions within tight schedules can be inadequate review and analysis of the issues involved. Moreover, structuring a penalty for an agency for missing a deadline poses difficulties and, as a result, deadline schemes usually act more to pressure rather than coerce agencies to act on utility applications for transmission line projects. Involvement of xulti-atate, rec1era1, or Independent Agencies A final group of policy options are tailored especially for application in the siting of long distance transmission lines which involve several states. The National Coal Council has been particularly outspoken in calling for increased federal government involvement i.n siting power lines. The group has written to the Department of Energy that "The Secretary of Inergy should declare that it is in the national interest to have in place --and to reinforce as the need arises --strong interstate electric transmission networks." According to the Council, the Secretary "should intervene or otherwise appear before state and local regulatory bodies that are considering the construction or siting of transmission lines O'l'A PINAL SITING REPORT Page 50 JAMBS S CANNON
PAGE 118
that have interstate or regional implications."58 Increasing the powers of the Federal Energy Regulatory Commission could provide another method of bolstering the federal role in interstate transmission line siting. In this regard, the Coal Council has urged the Department of Bnergy to support PBRC "in its efforts to resist state encroachment upon its jurisdiction over the interstate transmission of electrical energy. "59 PIRC or another federal agency could affect siting indirectly by creating "modal" siting procedures or transmission line application review criteria which could help standardize procedures used by state regulatory agencies. Expanding the concept behind the congressionally established Northwest Power Planning Council to other regions could offer another avenue to increase federal and multi-state involvement in. transmission line siting. Alternatively, congressionally-approved siting "compacts" of states through which a tran6mission line is proposed to pass could create ad hoc multi-state daciaionmaking bodies with broad siting powers. Informal federal-state transmission line siting dispute resolution boards could provide forums where clashing interest groups can come to discuss and possibly resolve their differences. More dramatically, soma have suggested that the federal government or soma independent dispute resolution O'l'A PINAL SITING REPORT Paga 51 JAMES S. CANNON I 11'
PAGE 119
organization, such aa the American Arbitration Society, could be empowered to make decisions on issues about which regulatory agencies in different states disagreed.60 Bnhoncad Public Participation Moat utilities and state and federal regulatory agencies have established extensive public participation programs which include participation in the review of transmission line projects. These programs seek to provide early disclosure of information and to solicit public input into the designing of utility projects. Citizen review, evaluation, advisory, and participation committees are cOimlOnly formed to help shape transmission line projects. Moreover, individual interest groups can make their opinions known through public cementa, formal interventions, and legal appeal processes which occur at a number of points under moat siting procedures. Development of new models for public participation specifically geared to the circwutancea cODDonly encountered during tranallission line siting is an ongoing process which, if affective, could alleviate some impedimenta to siting. Toward that goal, the Edison Electric Institute convened a Task Force of public participation in 1982 entitled "Workshop on Utility Bxperience with Advanced Public Participation in Planning" and aubaequantly sponsored the preparation of a lengthy study of the OTA PINAL SITING RBPORT Page 52 JAMBS S. CANNON / I f..)
PAGE 120
issue entitled Public Involvement in Energy Facility Plannincu. The Electric Utility Experience. This 451 page book offers a collection of professional papers that its introduction claims "stands as the moat comprehensive work to date on how the open planning process has functioned under the auspices of electric companiea."6l 'l'BRBB CASI STUDIES The following three case studies illustrate transmission line projects which have experienced significant opposition. Thay off er examples of how impedimenta to transmission line projects surface in real situations and are resolved or, in some cases, not resolved. The case studies include examples of "innovative" as wall as traditional power line approval mechanisms, thereby providing indications of how well some proposed "solutions" to power line siting bottlenecks actually work. In each case, interest groups have exerted their influence at different stages in the decisionmaking process to impede or delay the project or to necessitate a substantial modification to the project design. In these three projects opponents of transmission line construction have concentrated their efforts at the state, federal, and local levels for approving power line construction, respectively. Opposition to the Coal Creek Project O'l'A PIRAL SITING REPORT Page 53 JAMES S. CANNON I I(,,,
PAGE 121
in Wisconsin focussed on the state siting process. In the case of the Ole Project in New Mexico, the federal environmental review process has already taken four years with no end in sight. Finally, controversy surrounding the Washington DC loop has bean moat vocal affectively expraaaed by way of the county court system. The coal creek Project The major components of the Coal Creek project include a 1,015 Mw coal-fired power station in Horth Dakota owned by two Minnesota utilities and a 436 mile, 400 KV direct current BHV transmission line connecting the plant with two shorter 345 EHV KV and one 115 KV alternating current line within the utilities' service areas (see map). The utilities involved are the United Power Association (UPA) and the Cooperative Power Association (CPA), both generation and transmission cooperatives serving a total of 33 distribution mambera.62 The Coal Creek project began in 1972 when the utilities agreed to work together on a power plant and transmission line feasibility study and an application to the Rural Electrification Administration for financing. A federal Environmental Impact Statement was completed in 1974 and preliminary approval was granted for the financing. Although state agency regulatory approval for the power plant and for a portion of the transmission line waa obtained in Horth Dakota, significant OTA PINAL SITING REPORT Page 54 JAMBS S. CANNON / I 1
PAGE 122
BEST COPY AVAIL/\8LE MANITOBA I r ___ CA~ADA --.G h NO~:--~~------r----.. t'-\.,--'\ -,_., ....... \ MINNESOTA ~ l t L._ ._ .._-----a-----\ l I f, I I I I '. L ______________ __j Flaure 9.1 M.Jor feturee of the Col Creek Project 219
PAGE 123
opposition to the project began to gel in Minnesota. The major issues of contention ware the economic and land use impacts of the power line on the prime agricultural areas through which it waa to traverse and the potential threat to public health posed by the electrical field created by the line. The Coal Creek Project examplif ias the dilemma faced in the siting of long distance transmission lines of distributing fairly the project's total anticipated costs and benefits. Urban residents in Minnesota would benefit from the reliable source of low-coat electricity made available by the project. However, lifestyle impacts, notably perceived public health threats and interference with the agricultural economy, would be borne by a relatively small group of people living near the line itself who stood to gain little from the project. Although numerous actions were taken to balance the benefits, including condemnation payments which averaged $52,400 per mile for a 160 foot wide right of way, a consensus among interest groups was never achieved. Ironically, the lengthy and bitter controversy unfolded in one of the first states to establish a "lead agency" siting approval process with the expressed purpose of speeding transmission line projects while facilitating constructive public participation. The Coal Creek Project was the first transmission line project to be brought before the Minnesota Bnvironmental O'l'A PINAL SITING REPORT Page 55 JAMES S. CANNON
PAGE 124
Quality Board (BQB), the lead agency named in the 1973 Power Plant Siting Act. The multi-stage review process involved active participation by citizen evaluation committees, the public at large, the utili tie... and other state agencies. By law, a decision by the EQB overrides any contrary action by another state agency and local or county governments. The first step began in April 1975 and ended in October 1975 with the issuance of a Corridor Certificate. During this time period, 82 witnesses submitted nearly 1,870 pages of testimony at public hearings. The second stage ended with the issuance of a Certificate of Need on April 2, 1976, after hearings at which an additional 1,151 pages of testimony were collected. About this time the state also completed an Bnvironmental Impact Statement on its own, which included opportunities for public cODDDent. Pinally, on June 3, 1976, the EQB issued the final route construction permit. In total, over 80 public meetings and hearings ware held during the review process and almost 6, 000 pages of transcript were collected. During the course of the review process, nwaerous modification to the design of the line ware made to acconnnodata local concerns Por example, the minimum height of the power lines was raised from 35 to 50 feet to prevent interference with aerial crop dusting and seeding and irrigation equipment. In the aftermath of the siting board's approval of the O'l'A PINAL SITING REPORT Paga 56 JAMBS S CANNON
PAGE 125
project, nine separate lawsuits were filed seeking to have the approval overturned. The suits were consolidated by the Minnesota Supreme Court and the case was heard by a special three-parson panel of District Court judges appointed by the Supreme Court. Approval of the project by the siting board was upheld by this panel on July 15, 1977, over one year after the final siting board action and more than two years after the regulatory agency review process began. The Supreme Court upheld the panel's decision on September 30, 1977. While the formal review and appeal of the siting permits was underway, several other actions took place which were designed to alleviate the concerns felt by the project's opponents. For example, the EQB requested the state Department of Heal th to conduct a thorough study of health and safety effects of EHV transmission lines, which was completed in October 1977. The major finding, unfortunately, was that insufficient data existed to define public health impacts from power lines. The Governor also became personally involved in a number of instances. First, ha proposed the establishment of a science court to grapple with the public heal th issue. A Technical Review Committee was, in fact, eventually established in 1980, but UPA and CPA refused to delay construction to await the results of additional research. In February 1977 the Governor's office retained the American Arbitration Association to attempt to resolve opinion differences through arbitration. During this time, the Governor even made OTA PINAL SITING REPORT Page 57 JAMES S. CANNON I J. l
PAGE 126
surprise visits at the homes of the project's opposition leaders. Construction of the Minnesota portion of the power line began in October 1977 and lasted for approximately one year. Despite the unsuccessful challenge to the project during the regulatory review and appeal process, opponents to the project continued to press their concerns, mainly through public demonstrations, which occasionally led to violence, vandalism, and intimidation of construction workers. Over $2 million worth of equipment damage, including the destruction of 16 steel power line towers and 10,000 insulators, was blamed on vandals. About $5 million was spent for a private security force which worked round the clock during construction. Additional local and state police personnel were also assigned to patrol the construction zones. At one point the Minnesota Governor ordered 200 State Patrol officers into the area. Nonetheless, protests continued and scores of arrests were made and crowd dispersion actions, such as mace spraying, were undertaken. Protesters counterattacked at one point by spraying the State Patrol with liquid ammonia fertilizer. In another incident, a security guard and a local sheriff's deputy were shot at by an alleged vandal. Several arrests were made and one conviction resulted from this incident. Deapi ta this inter erence the power line was completed in O'l'A PINAL SITING REPORT Page 58 JAMBS S. CANNON
PAGE 127
late 1978 and it has been operational since April 1979. However, the magnitude of public opposition to the project, especially during the construction phase, attests that the concerns of a number of interest groups were not satisfactorily accODDDodatacl during the certification and licensing process. The Coal Creek project example demonstrates clearly the implications of failure to resolve a perceived mismatch between the recipients of the benefits of long distance transmission projects and the interest groups which are subject to sOJ1e of its coats. Despite the existence of a siting process in Minnesota slanted toward the solicitation and resolution of public concerns and the active involvement of Governor's office as a mediating force, the Coal Creek experience shows how difficult the crafting of a long distance transmission line project can be. The Ole Project The Ole project involves the construction of a 345 rv AC transmission line to connect two existing BHV transmission lines ownacl by Public service Company of New Mexico (PNM). The line, approximately 70 miles long depending on the selected route, would provide a link between the Ojo power line, which connects the utility's San Juan Generating Station with portions of northern New Mexico, and the Norton switching station, from which power can be supplied to major power demand regions in central and northcentral New Mexico including the government laboratories at Loa Alamos and the city of Albuquerque. The project, in OTA PINAL SITING REPORT Paga 59 JAMES S. CANNON
PAGE 128
effect, extends the San Juan to Ojo line to Horton and hence it is frequently called the Ojo Line Extension, or Ole, project (see maps).63 Anticipated benefits of the project include increased transmission capability in Loa Alamos and economic and reliability benefits to the state's transmission grid through improved system interconnection. Several possible transmission line corridors could potentially be followed to accomplish the linkage proposed by the Ole project. A number of proposed con igurations, called the mountain" routes, travel largely through National Forest land across the Jemez mountains Other configurations, termed the valley routes, follow largely private and Pueblo Indian lands through the Bapanola Valley. In addition to the f crest lands, administered by the U.S. Forest Service, and the Pueblo Indian lands, administered with the approval of the u.s. Bureau of Indian Affairs, other federal lands administered by the Rational Park Service and the Bureau of Land Management are within the general vicinity of proposed routes. Because of the involvement of several federal agencies in granting rights-of-way for the project regardless of the final route configuration, completion of an Environmental Impact Statement (BIS) for the project was required under provisions of Section 102(2)(c) of HEPA. OTA PINAL SITING REPORT Page 60 JAMES S CANNON
PAGE 129
OG 1tal ital ioua BIA ciae ator ) .aeDt Loa ,1c lblic i.ta); >DiDI it1); mita iaia Juan .eatal !fllleDt .le oa. ,rated 1pital -the rs are s, are ayatea lecauae aae P!IM lilliOD ~ndea.t t power lu,on a oc.-:ur typic .rdell OD trau .ptaiDI 1il11rea. I BEST cnr:~v ,~ V I j f'' J 'i 1 ;,__ ~--\,. ..... ... ~........ I._. .. = :11-.-~---J--------..... ~~..,,..--7-:.-.;;-..z.-. ----.. ..... -------.... --..;.; -... --... ... : I_ .... -=----~,..;::; --__________ _,_.. ___ -. -. ---------' _,acre ----------I-3 Jiu ta...,.. 0 --.................
PAGE 130
RIO ARRIBA COUNTY N811NANDU (NT) SANDOVAL COUNTY .. U11811ATIIIG ffATIOII IWITCIIINCI STATIOII IUNTATIOII MIii 11111 1911 IINMPACIJ'n II JOINT Otl OTMD PACIUTY 0 0 -- --\ TAOS .~OUNT \.wacv '----.r-, r------; I I I SANTA FE COUNTY I OJO UNe IXTINSt,iN MIis TMNSIIIMION "'OJIC LOS ALAMOS AND SAN AREAIXllnNG TRANSMISSION SYS1 /.iJi
PAGE 131
The environmental analysis process began in early 1984 with the selection of the Bureau of Indian Affairs as the lead federal agency for the environmental review process, in view of the posaible impacts of the Ole line on Indian Pueblo lands and on land deemed aacrad to Indian cultures in Rew Mexico. A Notice of Intent to prepare an BIS was announced in the Pederal Register on July 25, 1984. A "scoping" process was then initiated to solicit input aa to the significant iasues which needed to be addressed in the BIS. Piva public hearings were held followed by a public comment period for aubmisaion of written statements which ended on September 30, 1984. Eleven critical issues were identified for further in-depth analysis. Completion of the Draft BIS took the BIA about one year. The document, spanning several hundred pages, was released for public review on October 22, 1985. The initial deadline for public cODDDent was January 2, 1986, but this deadline was extended twice until the end of the month. During the comment period four public hearings on the Draft BIS were held. In total 151 written comments and 62 oral stataments were catalogued by the BIA. Although the c011111enta addressed a large number of issues, four concerns appeared to predominant in the c0111Dents, as followa: o Bead Many parties including environmental groups, Pueblo Indiana, Bapanola Valley citizen associations, and the New Mexico State Inergy and Minerals Department O'l'A PINAL SITING REPORT Page 61 JAMBS S. CANNON
PAGE 132
questioned whether the power transmission capability added by the Ola project waa needed to supply future electricity demand. Alternative lower demand projections ware offered baaed on enhanced conservation and load management prograaa. Higher projections of available electricity supplies ware alao outlined including contributions fr011 coganeration, out-of-state power imports, and other electricity sources not dependant on the Ole Project. A8 part of the NEPA process, the BIA was required to analyze a "no-action" alternative of not proceeding with the project. Opponents to the project frequently sited lack of need as the rationale. for adoption of the no-action alternative. 0 Impact on Valley Lfpda. Asaociationa representing residents of the Bspanola Valley, including Pueblo Indiana and reaidenta of small, predominantly Anglo and Hispanic conmnmitiea, raised iasuea related to the visual impacts of the power linaa, disruptions of life styles and livelihoods, and public health threats from expoaura to the electrical field generated by the line if it was situated along the proposed valley routes. o oeaacration of sacred Pueblo Indian Sites. Pueblo Indian organizations and environmental groups OTA PINAL SITING REPORT Page 62 JAMES S. CANNON
PAGE 133
complained that the proposed mountain routes would pass close to a number of sites deed sacred to Native American cultures in Hew Mexico. o Impact on Wildro Aral A number of environmental group complained of high visual impacts and other advarae environmental effects in the Santa Pe National Poraat, such aa on wildlife, if the line was built along the propoaed mountain routes. The BIA reviewed the public comments and published a Pinal BIS on the project on August 15, 1986. The Pinal BIS contained over 800 pages, including copiea of all public comments, and waighed over 5 pounds In it, the BIA endorsed aa a proposed action construction of the Ole line along one of the mountain configurations. Complete environmental reviews of several mountain and valley routes were included in the BIS as well as a diacuaaion of the no-action alternative. On September 26, 1986, the Rew Mexico BIA off ice issued a Record of Decision which specifically endorsed one mountain route, thereby clearing the way for the issuance of the requisite federal agency rights-of way. Shortly thereafter, several organizations, including the Sierra Club, another environmental group called Save the Jemez, a number of Indian Pueblos, and the Haw Mexico Attorney General's O'l'A PINAL SITING RBPORT Page 63 JAMES S. CANNON 1Jf
PAGE 134
Office appealed the Record of Decision to the Bureau's Director in Washington DC. 64 The appeal was rejected several months later. The appellants then pursued their objections in a lawsuit filed in u.s. District Court. The lawsuit alleges that the Pinal BIS inadequately complies with the requirements of NEPA by, for example, failing to establish a need for the project, and that the BIA approval of the mountain route violates the federal Indian Religious Preedoa Act by endangering Native American sacred sites. The case is expected to come to trial beginning in the Spring of 1988. Until and unless the case is finally resolved supporting the selection of a particular transmission line configuration in compliance with RIPA, the federal right~-of-way will not be issued and it is unlikely that the utility will submit an application to the Hew Mexico Public Service Commission thereby initiating the state agency approval process The waahinqton pc Loop Since an intarutility agreement was signed by utilities in the Washington DC area in 1972, several stretches of 500 KV transmission lines have been built as part of what is envisioned as a loop of 500 KV lines surrounding the nation's capital. The loop was designed to improve reliability of 5ervice for a number of utilities, mainly Baltimore Gas and Electric Company, Virginia Electric and Power Company, and the Potomac Electric Power O'l'A PINAL SITING REPORT Page 64 JAMES S. CANNON
PAGE 135
Company, and to improve tranamiaaion capability among midAtlantic states. Completion of the loop would provide up to 5000 KW of regional power transfer capability to the area.65 All sections of the loop have been constructed with the exception of three small stretches including a 10.5 mile stretch from Brighton to High Ridge, Maryland (see map). Failure to gain final authorization to construct this stretch has delayed completion of the loop. Nearly 12 years have elapsed aince the initial application to build thia section was filed. Planning for the Washington Loop began in 1965 with the formation of the Bast Central Coordinated Interregional Study Group composed of representatives from a number of utilities. The group produced a study in 1967 recommending consideration of a loop project and the need for such a transmission line was confirmed in another study performed by a smaller group of utilities and released in October 1969. The project itself was launched in 1972 and moat sections of the line were completed in the 1970's. The problematic stretch between Brighton and High Ridge falls in the service area of the Potomac Electric Power Company (PEPCO). The company filed on July 26, 1976, for a Certificate of Public Convenience and Necessity (CCN). Significant opposition to the project developed among residents of Howard and OTA PINAL SITING RBPORT Page 65 JAMBS S. CANNON /_I/
PAGE 136
.... ... '"!, ~-J.11111. JIii. m. 1110 ._ --_,11111 ITIIIII ADAPTED ROM MAP PROVIDED BY PEPCO BEST COPY AVAILP\3L TO CONIIMUCIN --) ( l Figure 2 The Washington 500-kV loop 203 ,. C w J I
PAGE 137
Montgomery counties, Maryland through which various configurations of the proposed line traversed. PEPCO made several alterations to its initial proposal in response to the concerns of opponents in an uaended application filed on April 7, 1977. The project was 1eviawad first by the Maryland Department af Natural Resources, the lead transmission line siting agency in the state. After an initial favorable ruling on the project by the Department, formal hearings on the project began. The hearings lasted nearly a year, ending on May 23, 1978, after collection of over 6,000 pages of testimony from over 70 witnesses. Two public meetings ware also held at which 47 people spoke. The principle point of contention involved the visual impact and potential health threats of the transmission line in the densely populated suburban areas through which it was proposed to pass Thia concern lad some parties to propose a number of alternate siting confiqurationa designed to avoid certain areas of concern and it lad others to investigate the need for the overall loop roject and to argue that its completion was not necessary to ensure reliable transmisaion capability. Por example, the government of Howard County denied that the line was needed, but concluded that if it was built, it should be constructed along a route falling largely in Montgomery County. On the other hand, the government of Montgomery County believed that the line was needed, but supported a route traversinq Howard OTA PINAL SITING REPORT Paqe 66 JAMES S. CANNON
PAGE 138
County for more than two-thirds of its distance. On November 16, 1978, the Department of Natural Resources recommended that the project proceed and endorsed a route largely falling mostly in Boward County. Six months later on April 6, 1979, the Hearing Bxaminer for the Maryland Public Service Commission ( PSC) issued a proposad order granting the CCR. By this time, the approval process had consumed nearly three years. Several opponents to the project than appealed the proposed order to the Public Service Commission. That appeal was denied 11 months later only to be followed by several motions for a rehearing before the Commission filed on April 4, 1980. Moreover, the order was appealed to the Montgomery County Circuit Court on April 3, 1980. Under state law, the Commission was forced to delay conaideration of the motions for rehearing until the Circuit Court made its ruling. After a lapae of more than a year during which the case was never brought before the Court, the appeal was withdrawn and the PSC once again took up the rehearing motions. The motions were denied on July 2, 1981, only to be followed by further appeals back to the Montgomery County Circuit Court and to Circuit Courts in Howard and neighboring Prince George's counties. In March 1982 the caaea ware consolidated in the court in Howard County, but consideration of the case did not proceed OTA PINAL SITING REPORT Page 67 JAMBS S. CANNON I.JI
PAGE 139
far before a legal battle tangential to the transmission line issue emerged concerning the rights of one of the plaintiffs to tAke oral depositions of individual members of the Maryland PSC. Nearly two years and two court decisions later, the Maryland Court of Appeals ruled on July 12, 1984, that Commissioners could not be deposed. Some 15 months more elapsed before the Howard County Circuit Court upheld the granting of the CCN on October 14, 1985, more than 6 years after it was initially approved by the Hearing Examiner. Construction of the transmission line has still not begun, despite issuance of the CCN. PEPCO currently is working to obtain variances from local zoning regulations, al though it is not clear from state law whether such variances are required for a project which has been issued a CCR. CONCLUSIONS The complexities involved in the siting of large transmission line projects are significant, especially with regard to multi-state projects designed to promote interutility power sales. Nevertheless, the simple fact is that most power line projects are successfully sited in a timely fashion if not to the satisfaction of all the interest groups participating in the decisionmalcing processes Even in the face of increased demand for new transmission capacity anticipated by electric OTA PINAL SITING REPORT Page 68 JAMES S CANNON 1~<
PAGE 140
utility industry restructuring proposals, current siting procedures are probably adequate, although inefficient. A number of impediments to transmission line siting can be clearly identified, although sound reconmendations to remove those impediments are not so obvious. A dearth of information about future transmission needs and a lack of coDDDunication among regulatory agencies appear to encourage confusion in siting processes. Conflicting regulatory agency priorities, objectives, and jurisdictions can add Byzantine elements to siting processes. Multiple decisionmaking procedures within overall siting procedures permit interest groups to pick the decisionmaking arena of their choice in which to express their views or to repeat the same concerns before different audiences recognizing that a single success can achieve their objective. Many proposals to alter siting procedures could have negative as wall as positive affects in practice, sometimes leading to solutions which create conditions as bad or worse than the problems they are designed to correct. Por example, creation of "one-atop" siting entities with final decisionmaking authority can greatly simplify and expedite siting, but it can also undercut public participation, information dissemination, and the exercise of statutory responsibilities by other regulatory agencies. Bolstering long range transmission planning can provide more useful analytical information for decisionmakers, OTA PINAL SITING REPORT Page 69 JAMES S. CANNON
PAGE 141
but collection of this information can add time and coats to siting processes and identify new uncertainties and information needs. Moat of the proposals to address the impedimenta to transmission line siting discussed in this paper are being teated to a greater or leaser degree in specific atatea or regions of the country. Perhaps the moat prudent advice is to encourage the continuation and expansion of these efforts to improve siting procedures. Greater attention to the implementation of innovations to traditional siting protocols under virtual "test" conditions coupled with redoubled efforts to share the resulting experiences and insights could produce significant improvements to siting proceaaea over time without undercutting along the way what appears to be a basically sound process. O'l'A PINAL SITING REPORT Page 70 JAMES S. CANNON
PAGE 142
Cannon, Jamea B11ponaibility. BIBLIOGRAPHY s. controlling Acid Raina INFORM, Inc. Raw Yorks 1987. A New View of oucaik, Dennis w., editor Public Inyolyament in Energy Pacility Planning; Tha Electric utility Experience. weatview special Studies in Natural Resource Management. Weatview Presa, Boulder, Colorado: 1986. The National coal council, Interstate Transmission of Electricity, Washington DC1 June 1986. The National Governors Association, Committee on Energy and Environment Task Poree on Blectricity Transmission. Moving Power: Plexibility for the Puture. Washington DC1 1986. The National Regulatory Research Institute, Non-technical Impedimenta to Power tran1ara. columbua, Ohi01 1987. The Horth American Electric Reliability Council, 1987 Electricity Supply i Pemnn4 for 1987-1996, Princeton, Hew Jersey: November 1987. The Horth American Inergy Reliability Council, Reliability Review .:.1985. Princeton, New Jerseys 1986. The Public Service Commission of Weat Virginia, State Survey of Transmission certification and Siting, and Planning Processes. Unpublished report, Charleston, Weat Virginia1 November 13, 1987. O'l'A PINAL SITING REPORT Page 71 JAMBS S. CANNON
PAGE 143
POOTHOTES 1. The National coal council, Interstate Transmission of Blactricity, Washington DCs June 1986. Paga 19. 2. The North American Blactric Reliability Council, 1987 Blectricity supply i PeJPnnd for 1987-199, Princeton, New Jersey: November 1987. Pages 62 and 63. 3. Ibid. Paga 62. 4. The National Governors Association, Committee on Energy and Environment Taak Poree on Blectricity Transmission. Moving Power: Plaxibility for the Putura. Washington DCs 1986. Forward. s. The National Coal Council, op, cit. Page 23. 6. James S. Cannon. Controlling Acid Rain: A New View of Responsibility. INPORM, Inc. Hew Yorks 1987. Page 25. 7. Charle Komanof f, Power Plant coat Escalation. Komanof f Inergy Aasociataa, New Yorks 1981. Paga 2. 8. James s. cannon, controlling Acid Rain. op. cit. Page. 11. 9. The National Coal Council, op. cit. Page 8. The statistics represent average fuel prices for all fuels burned in power plants within the respective statea. Fuel costs constitute a major portion of the total price of electricity, but not the only coat reflected in rates to the consumer. 10. Ibid. Page 1. 11 James s cannon. coal conversion at New Jersey utilities INPORM, Inc. New York: 1983. Paga 13. 12. Jamaa s. cannon. Acid Rain and Energy: A Challenge for New Jersey. INPORM, Inc. 1984. Page 4. 13. James s. Cannon, controlling Acid Rain. op. cit. Page 33. 14. The North American Energy Reliability Council, Reliability Review -198S, Princeton, New Jersey, 1986. Cited in The National Coal Council, op. cit~ Page 24. 15. The National Coal Council, op. cit. Page 29. 16. The North American Blectric Reliability Council, 1985, cit. Cited in The National Coal Council, op. cit. Page 27. O'l'A PINAL SITING REPORT Page 72 JAMBS S. CANNON
PAGE 144
17. The National Governors Association, op. cit. Forward. 18. The National Regulatory Research Institute, Non-technical Impediments to Power Tranafara. Columbus, Ohio: 1987. Page 111. 19. The National Coal Council, op. cit. Page 28. 20. Rational Governor' Association, op. cit. Page 17. 21. Public Service Commission of Wast Virginia, State Suryay of nooeml a ion cartif !cation and siting, and Planning Procaasaa Unpublished report, Charlaatnn, West Virginia: November 13, 1987. Paga 9. 22. National Governors Association, op, cit. Page 16. 23. Public Service Commission of West Virginia, op, cit. Page 6. 24. Ibid. Paga 4. 25. Ibid. Paga 5. 26. jbid. Pages 3 and 7. 27. Ibid. Page 3. 28. The National Governors Association, op, cit. Page 11. 29. The National Coal Council, op. cit. Page 33. 30. Public Service Commission of West Virginia, op. cit. Page 1. 31. The National Governors Association, op. cit. Page 10. 32. The Rural Blactrification Administration, Rifle to San Juan 34S KY Tr101m111ion Lina and A110ciatec1 racilitiea: Pinal Environmental IP1Pfct statement, Washington DC1 March 1984. Paga 1. 33. National Regulatory Research Institute, op. cit. Page 161. 34. Public Service Commission of West Virginia, op. cit. Page 1. 35. National Regulatory Research Institute, op. cit. Page 96. 36. The National Governors Association, op. cit. Page 18. 37. Northwest Power Planning Council, Western Electricity Study Briefing Paper: Interregional 'l'ran11ctiona Portland Oregon: December 28, 1987. Preface. OTA PINAL SITING REPORT Page 73 JAMES S. CANNON /yo
PAGE 145
38. National Regulatory Research Institute, op. cit. Pages 46 and 47. 39. Ibid. Paga 90. 40. The National Coal Council, op. cit. Page 2. 41. Ibid. Page 2. 42. The National Governors Association, op, cit. Page 23. 43. National Regulatory Research Institute, go. cit. Page 169. 44. The National Governor Association, op, cit. Paga 11. 45. National Regulatory Research Institute, op. cit. Page 47. 46. Waatview Special Studies in Natural Resource Management, edited by Dennis w. oucsilc, Public Involvement in Energy Pacility Planning, The Electric utility Ezpariance, weatview Preas, Boulder, Colorado1 1986. Paga 5. 47. Amory Lovins, Soft Energy Paths. Ballinger Publishing Company, Cambridge, Masai 1977. Paga 18. 48. coal week. September 8, 1987. Page e. 49. Public Service Comission of Wast Virginia, op, cit. Page 8. 50. The National Governors Association, op, cit. Page 18. 51. The Washington Utilities and Transportation Commission, Office of Policy Planning and Research, Least-coat Planning and Ayoidad coats, Byaluatina B11ource1 in an uncertain Future. Olympia, washington1 June, 1987. Pagea 1 through 3. 52. Ibid. Page 25. 53. National Regulatory Research Institute, op, cit. Paga 156. 54. The Electric Power Research Institute, op. cit. 55. The National Governors Aaaociation, op. cit. through 30. 56. Ibid. Page 10. 57. Ibid. Page 23. Pages 28 58. The National Coal Council, op. cit. Secretary Herrington. Attached letter to OTA FINAL SITING REPORT Page 74 JAMES S. CANNON If//
PAGE 146
59. Ibid. Attached letter to Secretary Herrington. 60. National Regulatory Research Institute, op. cit. Page 159. 61. Westview Special Studies, op, cit. Pages 8 through 11. 62. Unless otherwise noted this case study was drawn from a chapter in Dennie Ducaik book, op, cit. entitled "Public Participation in Routing 'l'rannliaaion Linea a A Program Bom of Adversity" written by Dan KcConnon of UPA and from an article, "The llinneaota Power-line War" in the July 1983 issue of the IBBB Spctrwp written by Sheldon Hains of the Minnesota Bnvironmantal Quality Board. 63. Unless otherwise noted, thi case study ia drawn from information contained in the .l.i.n.a_l ....... l~DwY.iyrwoympa ... ~nyt~a.l ....... IDlpa ....... ct~ statement a Propoaad 010 Lina 1rt1011on, published by the u. s. Bureau of Indian Affairs in August 1986. 64. Information about events after iaauance of the notice of Decision was obtained from interviews with representatives from an environmental group, state agenciaa, and several Indian Pueblos affected by the project. 65. Unless otherwise noted, information for this case study was obtained from a chapter in the Rational Regulatory Research Inatitute op, cit. written by Casazza, Schultz, Aasociataa, Inc. and entitled "Caae 11 Cloaing the Washington 'l'ranamiaaion Loop." Pages 200-220. O'l'A PINAL SITING REPORT Page 75 JAMES S CANNON
PAGE 147
OTA DRAFT WORKING PAPER ENVIRONMENTAL EFFECTS OF INCREASED COMPETITION IN THE ELECTRIC POWER INDUSTRY May 1988 Prepared under OTA Contract No. HJ-6585.0 by Kennedy P. Maize 1819 Mt. Ephraim Rd. Adamstown, Md. This is a DRAFr OTA Workin1 Paper. It is bein1 circulated for review only and should not be quoted, reproduced, or distributed. The conclusions expressed in this report are those of the authors and do not necessarily represent the views of OT A. This report has not been reviewed or approved by the Technoloay Assessment Board. /Y.J
PAGE 148
CONTENTS I. In troductlon....................... . . . . . . . . . . . . 1 II. Basic En,lronmental Standards ~ 6 III. Industry-Wide En,lronmental Issues............................................................................ 9 Tbe Fuel Cycle 9 Combusdoa.......................... . 13 Transmission and Distribution .......................................................................... 15 IV. Scenes of Cbanae: ne Chan1ln1 Electric Utility Industry 20 V. Case Studies . . . . . . 44 1. The Transmission Quaamlre: The New York Power Lines Project, Colstrip, Coal Creek, and Klein Independent School District ... ..... ...... .. . 45 2. Blddlna In Massachusetts: A Glimpse of the Future? .. .. ... . 5S VI. Coacluslons 63
PAGE 149
Kennedy P. Maize 1819 Mt. Ephraim Rd. Adamstown MD 21710 Contract: H3-6585.0 ENVIRONMENTAL EFFECTS OF INCREASED COMPETITION IN THE ELECTRIC POWER INDUSTRY I. INTRODUCTION Change is sweeping through the electric utility industry at a pace unseen since the 1930s.1 Driven by events in the 1970s, centrifugal forces have struck the once monolithic electricity utilities and divided them. The divisions are shown most clearly by the many ways that utilities now view their own future and the future of their business. As late as the early 1970s, there was general consensus in 1. See statement of Martha o. Hesse, Chairman of the Federal Energy Regulatory Commission, before the House Energy and Commerce Subcommittee on Energy and Power, September 10, 1987, pp. 1-3. For a good discussion of the regulatory history of the electric power industry during the 1920s and 1930s, see Kenneth S. Davis, ROOSEVELT: THE NEW YORK YEARS. ;y/
PAGE 150
Maize (H3-6585.0) the electric utility industry about the shape of the future. The future, the industry leaders believed, would look largely like the past. That meant a world of generally rising demand for electricity, driven by ever lower costs as larger plants brought economies of scalee The future structure of the industry also was clear: electric utilities were a natural monopoly, and would always exist as regulated businesses with a geographic franchise, a stipulated rate of return, and an obligation to serve within its franchise. By the late 1970s and into the 1980s, it became clear that the industry vision had been clouded. The present as it evolved during the so-called "energy crisis" years was far different than utility executives expected. The economies of scale that had characterized the 1960s proved chimerical. For some utilities, nuclear power turned from a dream into a nightmare. And as costs escalated, consumers began using less electricity and finding ways to use it more efficiently. As demand for electricity fell, the large central-station plants that the utilities had ordered to serve the expected growth in their markets often became white elephants, producing excess power at high prices. State regulators responded by revitalizing a little-used regulatory doctrine known as "prudence," declaring that large portions of the costs of these projects had not been prudent and could not be recovered in 2
PAGE 151
Maize (H3-6585.0) rates.2 But prudence reviews are a stop-gap, after-the-damage measure. Few people who had any experience with troubled utility building programs during the 1970s and 1980s, whether utility executives, environmentalists, ratepayers, or public officials emerged with much trust in the status quo. In the blunt words of New York Attorney General Robert Abrams, pondering two nuclear projects gone sour: "The present system of direct ratepayer financing of utility construction clearly warrants abolition. Under this system, the utilities continued the construction of Nine Mile Point Two and Shoreham long after unregulated businesses would have terminated the projects."3 As the familiar regulatory environment began crumbling, electric utilities found themselves facing additional challenges from the public in the form of continued and increased demands for better environmental performance. Responding to unrelenting demands from the public, federal and state environmental, health, and safety regulators during the 1970s insisted on costly new expenditures for pollution control and public health and safety. 2. For a characteristic industry description of the prudence phenomenon, see "Generating Change, Virginia Power's Chief Wants More Competition," Washington Business, Nov. 30, 1987, pp. 1, 22-23. 3. Robert Abrams, Brief on Exceptions, State of New York Public Service Commission, Case 29409: "Proceeding on motion of the commission as to the plans for meeting future electricity needs in New York State." 3
PAGE 152
Maize (H3-6585.0) Environmental concerns have long had been a key item on the public policy agenda of the nation's electric utilities, the largest consumers of raw energy in the nation4 as well as the sole commercial market for nuclear power plants. Environmental issues have led to important legislation to regulate utility air, water, and waste emissions and to improve public health and safety practices. At the local level, land use issues, particularly plant siting and power line corridor siting, have challenged the utility inudustry. One result of the push for conservation and alternate generation was the 1978 Public Utilities Regulatory Policies Act (PURPA). After a somewhat slow start, by 1980 PURPA was having a major impact on future electricity supply, primarily because it encouraged co-generation, or the generation of electric power by industries who also raise steam for industrial processes. There is nothing new about co-generation. Indeed, it was the dominant source of electric supply during the early years of the electric utility industry.5 How~ver, once utilities began building their own generating plants, they were reluctant to buy power from third parties and generally refused to offer prices 4. Electric utilities used about 36 percent of all the energy consumed in the U.S. in 1985 .(26.5 quads out of total consumption of 73.8 quads). New England Energy Inc., "Review and Analysis of Energy Markets," September 30, 1986, p. 35. 5. See Davis, op. cit. 4 I~
PAGE 153
Maize (H3-6585.0) acceptable to outside generators until forced to do so by PURPA. Despite o~position from some in the electric utility industry, cogeneration boomed in the 1980s, fueled by clean, lowcost natural gas burned in combustion turbines which offer higher efficiency than conventional steam turbine generators. These plants often were able to produce power cheaper than the local electric utility, while meeting the most stringent environmental regulations.6 At the same time, The Powerplant and Industrial Fuel Use Act of 1978 (passed as a companion measure with PURPA) banned use of gas in new electric utility plants. Also, many cogenerators fell below the minimum size limits for the more stringent environmental regulations --even though their cumulative impact was significant. Thus, an environmental loophole existed. Dissatisfaction with PURPA by some utilities, principally in California and Texas, coupled with the general dissatisfaction with the economic and regulatory status quo, has led the Federal Energy Regulatory Commission to consider changes in the way the 6 Often, gas turbines were less expensive than utility rates because of the rate shock effects of a large baseload plant just coming on line. On Long Island, for example, the rate shock effect of the Shoreham nuclear plant led Grumman, the area's leading employer, to install gas turbines with 50 megawatts of capacity rather than pay Long Island Lighting Co. rates. 5
PAGE 154
Maize (H3-6585.0) law is implemented.7 One element the agency is considering is competitive bidding to determine the price for power from cogenerators and other qualified bidders. It would be unfortunate if the changes that are impending have unanticipated effects on the environmental performance of the utility industry, or on gains in energy efficiency and conservation that utilities have been making the 1980s. This paper examines each of the OTA's five scenarios for the future of the electric utility industry from the standpoint of how those changes might impact the environment, natural resource conservation, and energy efficiency. II. BASIC ENVIRONMENTAL STANDARDS In analyzing how changes in the electric utility industry will affect environmental issues, it is important to describe some environmental reference points. These guiding policies and principals, firmly embedded in federal and state laws and regulations, can help policymakers evaluate the effects of different policy options. If a proposed policy violates one of the standards, that should serve to raise a warning that the policy should receive further scrutiny. 7 See "Remarks by FERC Chairman Martha O. Hesse," Energy Daily Utility Conference, Washington D.C., November 6, 1987. Also, "Remarks of Charles A. Trabandt, Commissioner," Energy Daily Utility Conference, Washington D.C., November 5, 1987. 6
PAGE 155
Maize (H3-6585.0) Energy conservation is preferable to new supply. This standard is embodied as national policy in several of the laws Congress passed in the mid-1970s, (EPCA, ECPA, etc.). As one analyst puts it, "A dollar invested in wise energy conservation makes more net energy available than a dollar invest in developing new energy resources."8 Conserving a kilowatt of power serves the same end as generating a kilowatt of power, but without the pollution that is inevitably associated with generation, and with no need for transmission and distribution. Public policy should be directed toward the maximum amount of conservation before any genera~ing strategies can come into play. Al1 costs must be fully internalized. In the past, electric utilities kept the price of power low by externalizing their environmental costs. In the 1950s, for example, utilities generally did not control particulate emissions, which kept rates low. But the particulate emissions had public health costs. Similarly, continued sulfur dioxide emissions from older, uncontrolled utility plants in the Midwest has a social cost, in the form of acid rain.9 The Clean Air Act of 1970 and the 1977 amendments rest on the principle that internalizing costs is a key to air pollution control. 8. Denis Hayes, "Energy: The Case for Conservation," Worldwatch Paper 4, January 1976, p. 23. 9. see OTA, ACID RAIN AND TRANSPORTED AIR POLLUTANTS: IMPLICATIONS FOR PUBLIC POLICY, June 1984. 7 /)(
PAGE 156
Maize (H3-6585.0) Market principles should pertain where a marketplace exists. Competition can serve the interests of consumers and the environment when there is true competition. Market economies are far preferable to regulation, from an environmental standpoint, because they set prices and allocate resources more efficiently, if social and environmental protection costs are fully internalized. As a recent analysis conclude, "Getting the prices right is more than a game economists play. Properly set energy prices that reflect their true costs minimize behavioral distortions and uneconomic fuel substitutions If energy producers and consumers receive incorrect price signals, resources are misallocated and economic growth and development are stunted."10 The converse of this is that regulation is necessary where competition does not exist. The mere assertion that a market is competitive does not make it so, but policy developments that attempt to eliminate monopolies and monopsonies are welcome. Environmental and public health values must have at least the same weight as economic values. Many federal environmental laws (NEPA, Atomic Energy Act, Clean Air Act, Safe Drinking Water Act, etc.) require that environmental and public health values supersede economic values. The 1986 Electric Consumers Policy Act 10. Mark Kosmo, "Money to Burn? The High Costs of Energy Subsidies," World Resources Institute, October 1987, p. 6. Also see William U. Chandler, "The Changing Role of the Market in National Economies," Worldwatch Paper 72, September 1986. 8
PAGE 157
Maize (H3-6585.0) mandates that the Federal Energy Regulatory Commission give the same value to environmental concerns such as wildlife as economic concerns such as jobs. III. INDUSTRY-WIDE ENVIRONMENTAL ISSUES The electric utility industry faces perhaps the broadest array of environmental issues of any industry in the nation. And that has been the fact for many years. Because electric utilities are so pervasive in the life of the U.S., and because their manufacturing facilities are so large, the industry has been at the cutting edge of environmental disputes, and a world leader in developing environmental control and monitoring technology. As the industry's structure changes, either through evolution or by conscious public policy, there is no reason to believe that environmental issues will recede into the background. Indeed, it is likely that environmental concerns will continue to be a major element in the industry's structural dynamics. Thus is it worthwhile to sketch out the environmental issues that arise in the industry, regardless of its structure. These include fuel cycle issues, combustion issues, and transmission and distribution issues. The Fuel Cycle The first set are fuel-cycle issues. For coal, this means 9
PAGE 158
Maize (H3-6585.0) issues related to the mining of coal, transportation, and waste disposal. Environmental issues related to burning coal are discussed under combustion. The environmenta1ll issues with coal start with land-use. One set of issues is use of public lands, primarily an issue in the Western U.S. Another set of land use issues relates to conflicts between coal mining and special categories of public lands such as national parks, wildlife refuges, and wilderness areas. In the East, land use issues relate to impacts of surface mining on private lands, and landuse impacts of underground mining, such as subsidence related to the growing use of longwall mining technology. Transportation of coal from mine to powerplant can also lead to environmental disputes. The two-decade-old dispute over coal slurry pipelines is a case in point. Finally, disposing of coal waste products -fly and bottom ash, scrubber sludges, and wastes from advanced technologies such as coal gasification --can set off environmental concerns because of concentrations of heavy metals and toxic organic compounds.12 The oil and gas fuel cycle raises some of the same public lands conflicts, particularly related to leasing for exploration ll. There are also significant health issues with regard to coal mining, including mine accidents and fatalities, and black lung disease. 12. The Resource Conservation and Recovery Act of 1979 exempts some, but not all, coal wastes from the most stringent requirements for land disposal. 10
PAGE 159
Maize (H3-6585.0) and production. Onshore, there is environmental tension between opening up lands for oil and gas development and preserving wilderness, as in the current dispute over exploration of the Artie National Wildlife Refuge. Oil and gas adds another public lands issue, as well: outer continental shelf leasing. Offshore, there have been protracted disputes about the environmental impacts of exploration and production on the Outer Continental Shelf, pitting energy developers against fishing interests. There is also a toxics issue associated with oil and gas drilling. EPA toxicological studies have shown that drilling muds and fluids may meet RCRA requirements, although the agency has proposed exempting them from full regulation. The nuclear fuel cycle has a number of well-known environmenta113 issues. Among them: land disturbances caused by mining, milling and mill tailings disposal, and spent fuel disposal. In addition, low-level waste disposal is becoming an increasingly important environmental issue, particularly as the states maneuver in and out of regional compacts under the 1985 low level waste amendments. Looming in the background of the nuclear fuel cycle is also the issue of reprocessing. Should the economics of reprocessing change dramatically and the nuclear industry attempt to reinstate reprocessing plan, this will set 13. There are also worker health issues associated with the nuclear fuel cycle, particularly the high levels of lung cancer found in uranium miners. 11
PAGE 160
Maize (H3-6585.0) off an enormous debate over both environmental issues and nonproliferation strategies. One area where environmental concerns over fuel cycle issues is just beginning to form is waste-to-energy. As local governments face growing piles of trash and diminishing access to landfills, they are increasingly turning to trash-burning facilities. PURPA provides a powerful boost to these facilities, by guaranteeing a market for the power at the avoided cost rate. As these facilities are proposed, local citizens have raised objections related to collection and transportation of the waste, plans for disposal of the potentially hazardous bottom and fly ash, and plans for further landfills to dispose of the ash. Leachates from the trash waste piles can raise water quality issues, which is particularly troubling because regulation of groundwater pollution is currently in a state of flux, with neither state nor federal regulators clearly in charge. Waste-toenergy projects often are heavily subsidized: The builder has access to low-cost capital through municipal borrowing and pollution control bonds: the operator is paid to take the trash, turning traditional costs for fuel into a revenue stream; and the project earns a revenue stream from power sales.14 Even hydroelectric projects have environmentally-sensitive 14. Another powerful subsidy is an EPA regulation that exempts facilities that burn hazardous or toxic waste from regulation if the waste is used to generate energy. 12
PAGE 161
Maize (H3-6585.0) fuel cycle issues, with water defined as the fuel. Hydro proposals often have public lands and wilderness components, particularly in the West. Also, hydro projects, including the kinds of small hydro that PURPA encourages, frequently run afoul of recreation and scenic values, and often have severe impacts on fish and wildlife.15 Combustion In addition to the fuel cycle issues, electric utility generation mix and combustion of fuels raise a different set of issues. Fossil fuels raise a whole series of air quality issues, including SO2, NOX, ~nd CO2 emissions. There are also issues of scale that arise here. Oil and gas have found their most recent markets in smaller plants, particularly combustion turbines, while coal plants tend to be much larger. However, developing coal technologies --particularly atmospheric fluidized bed and integrated, combined-cycle coal gasification --also are targeted at smaller, modular units suited for cogeneration and PURPA applications. Until quite recently, there was a serious discontinuity in regulating coal-fired boilers, which gave smaller boilers much more lenient sulfur dioxide standards than large boilers. The 15. For a good example of the kinds of adverse impacts that hydro development can pose, see the March 1988 FERC Environmental Assessment for the Hawks Nest project in West Virginia, and the U.S. Fish and Wildlife Service comments on the EA. 13 /~l
PAGE 162
Maize (H3-6585.0) 1971 New Source Performance Standards applied only to utility and industrial boilers of about 67 megawatts and above. But as a result of a law suit brought by the Natural Resources Defense Council and settled late in 1987, the 1.2 pounds per million Btu SO2 standard and 90 percent emissions reduction rule will apply to all fossil-fueled boilers above about 27 megawatts.16 And EPA is on a schedule to apply the 1.2 standard to even smaller coalfired plants by 1989.17 Trash burning facilities also raise a series of environmental issues related to combustion. In addition to the classic concerns about SO2 and NOX, trash facilities also produce dioxins, furans, and other toxic air pollutants18. Nuclear generation, of course, has a long and familiar list of environmental and public health disputes, including issues related to worker safety. Among the complex of issues that surround nuclear generation are routine air and water emissions, 16. While 27 megawatts is rather larga for a gas-fired combustion turbine or combined cycle project, it is on the smaller side for coal-fired boilers. 17. Telephone interview with David Hawkins, NRDC, 7 January 1988. Plants with a capacity factor of less than 30 percent and plants burning very low sulfur oil are exempted from the percentage reduction requirement. See also, "Small power plants now must meet pollution standards," Public Power Weekly, American Public Power Association, January 11, 1988. 18. Allen Hershkowitz, "Burning Trash: How It Could Work," Technology Review, July 1987, pp. 26-34. Also see Testimony of Dr. Houston Miller, George Washington University chemistry department, before Montgomery County Council (get date). 14 /St
PAGE 163
Maize (H3-6585.0) reactor safety, the source term, emergency planning, and the consumptive use of water (this is an issue in arid areas for any steam-generation technology). Transmission and Distribution Finally, transmission and distribution raise another set of environmental issues. While these issues haven't received the national attention that has been the case with air quality or waste disposal, they have often been just as intense and fractious at the local level as the more traditional environmental disputes. Transmission issues may become a greater part of the environmental debate in the future, as utilities change their spending patterns away from building plant and toward moving voltage. Transmission and distribution already consumes more capital than generation and, according to an Edison Electric Institute finance department survey, "the period 1986 through 1989 will see nuclear and coal generating plant expenditures down 40 percent; whereas, transmission expenditures will rise some 51 percent to $2.7 billion."19 Transmission and distribution are intimately tied into local land use and zoning, and disputes often take place in the institutional forums created for dealing with local land use and 19. Richard Braatz, "the Business and Financial Aspects of Electric Utility Restructuring," paper present at the Energy Daily annual utility conference, Washington DC, November 5, 1987. 15
PAGE 164
Maize (H3-6585.0) zoning problems, such as city, county and state zoning boards, boards of zoning appeals, and the like. Other venues for land use disputes over transmission and distribution can occur before state bodies that must license or permit a facility, in an eminent domain proceeding, or in state courts. Landowners who will see powerlines cross their property, particularly in urban or suburban areas but also in rural areas,20 often believe the line will lower the value of their property. Consequently, the disputes can be very bitter and intense (See Case Study 1: The Transmission Quagmire). Because they can extend for long distances, are often highly visible, and frequently pass through populated areas, siting power lines is usually a time-consuming and frustrating experience for the utility, regulators, and local citizens, with costly consequences.21 Once a project has been sited and permitted, there can also be environmental disputes related to construction, including issues such as erosion and sediment 20. Robert R. Thompson and William E. Phillips, "Agricultural Land Vale Changes from Electric Transmission Lines: Implications for Compensation," Right of Way, December 1985, pp. 24-27. 21. See remarks of Richard Disbrow, President, American Electric Power Service Corp., at OTA workshop, September 28, 1987. 16
PAGE 165
Maize (H3-658S.0) control, soil compaction, destruction of forests, and the like.22 Once a power line is built and operating, a different set of impacts come into play, although these issues likely will have been raised earlier during the siting and permitting processes. Visual impact, impact on bird life,23 audible noise and corona24 effects25, and, an area that has generated a lot of attention of late, bioilogical effects of electrical fields on wildlife, livestock, and human health.26 Another environmental issue related to existing powerlines is the use of pesticides and herbicides to clear rights of way. Visual impact plays a major role in transmission line disputes, in part because the visual presence of the lines often becomes a symbol of its total presence. The utility industry has 22. For a good discussion of the environmental impacts of powerlines, see Federal Colstrip Transmission Corridor Study Project Team, "Developing Numerical Values to Estimate Potential Environmental Impact of Power Transmission Corridors," Bonneville Power Administration, Nov. 1978, appendix. 23. Rene Males, EPRI Journal, March 1980, p. 49. 24. Air ionized by the high electric fields at the surface of the conductor creates the corona phenomena. 25. John A. Molina, Gerald A. Zerdy, Neil D. Lerner, and Dane L. Harwood, "Modification of Transmission Line Audible Noise Spectra to Reduce Environmental Impact," IEEE Transactions on Power Apparatus and Systems, Vol. PAS-100, No. 4, April 1981. 26. For a discussion of the evolution of environmental concerns about powerlines, see William E. Feero, "The Evolution of Electromagnetic Effects Issues," paper presented at the International Utility Symposium on Health Effects of Electric and Magnetic Fields, September 16-19, 1986, Toronto, Canada. 17 I (p I
PAGE 166
Maize (H3-6585.0) attempted to design less visible structures, although that can drive up costs. Some analysts have suggested that the present of a visible line is "a negative feedback mechanism" that could serve to slow growth of electrical use, by confronting consumers with the costs associated with electricity use.27 Existing powerlines can have an adverse impact on bird populations, including protected species such as the golden eagle, which use poles as perches for hunting and are "often electrocuted by contact with lines." There is also some evidence that overhead lines may increase avian mortality from collisiond and changes in behavior, although not much data on this problem has been accumulated.28 Powerlines also emit audible noise, radio frequency and television frequency interference, all the result of corona discharges. Because corona discharge is largely a function of weather, these problems are also associated with weather phenomena, generally being a greater problem in rain or fog.29 Corona noise is typically both low-frequency hums and buzzes, and 27. Thomas w. Smith, John C. Jenkins, John S. Steinhart, Kathleen A. Briody, David Schoengold, "Transmission Lines: Environmental and Public Policy Considerations," Institute for Environmental STudies, University of Wisconsin-Madison, June 1977, p. 44. 28. Males, op. cit., p. 49. 29. Smith, Jenkins, STeinhart, Briody, and Schoengold, op. cit. p. 39. 18
PAGE 167
Maize (H3-6585.0) random, high-frequency hisses and crackling. Studies suggest that the high-frequency component is more objectionable to listeners.30 Another product of corona discharge is ozone, a powerful oxidant that is a key precursor of smog. Ozone also has an affect on living tissue that is smilar to ionizing radiation, in that it causes tissues to break down and undergo chemical change. Ozone can irritate eyes, lungs, and circulatory systems of animals, including humans, and increase susceptibility to information and chronic disease through stress. It can also cause direct damage to vegetation.31 Powerlines may also have a more subtle impact on health. Evidence is accumulating that exposure to low frequency fields from powerlines and household appliances may be associated with or may promote cancer. The electric utility industry is devoting a greater share of its research dollars to this emerging field, trying to pin down the mechanisms that are at work, and determine what steps can be taken to prevent damage if it is occuring.32 30. John A. Molino, Gerald A. Zerdy, Neil D. Lerner, Dana L. Harwood, "Modification of Transmission Line Audible Noise Spectra to Reduce Environmental Impact," IEEE Transactions on Power Apparatus and Systems, Vol. PAS-100, No. 4, April 1981, p. 2122. 31. Smith, et. al, op. cit., p. 35. 32. EPRI Journal, op. cit., pp. 4-15. See also Mart H. Malakoff, "Electronic Smog," Not Man Apart, March-April 1988, pp. 10-11. 19 /fo3
PAGE 168
Maize (H3-6585.0) Finally, maintenance and vegetation management can have environmental impacts with existing transmission lines. Utilities generally want to establish a shrubland environment under their powerlines, because shurblands last far long than grasslands, once undesirable trees are removed. Since 1945, utilities have applied chemical herbicides to control vegetation. Notes one study, "Knowledge of specific species and their ecosystem interactions were not used to correlate vegetation management practices with herbicide application until very recently. Rachel Carson's SILENT SPRING in 1962 points out the misuse of pesticides ~nd the lack of available data on the effects of chemical treatments beyond the initial visible brown-out that results. The controversy concerning herbicide use is quite broad with no clear solution in sight."33 IV. SCENES OF CHANGE: THE CHANGING ELECTRIC UTILITY INDUSTRY Analysts and observers of the electric utility industry generally conclude that some structural changes in the industry are inevitable, regardless of governmental action. But the experts are in wide disagreement about how deep and fundamental those changes are, or should be. Some advocate regulatory fine tuning within the current strucure (Scenario 1). Others propose changes mostly in how bulk power transfer among a broader range of players can be accommodated (Scenario 2). Another set of 33. Smith, et. al., op. cit., p. 32. 20 Jr,/
PAGE 169
Maize (H3-6585.0) proposals would establish competitive bidding for all new power supplies as the determinant of avoided cost under PURPA (Scenario 3). Going beyond that, some have proposed ending the vertical integration of the industry, by spinning off all generation into competitive businesses (Scenario 4). Finally, there are proposals for a fully-deregulated generation sector, with transmission serving as a common carrier to all comers (Scenario 5) Each of these scenarios will have environmental consequences, which are often difficult to discern in light of the speculative nature of the proposals. Despite the inability to pin down the impacts with precision, it is still worthwhile to try to describe how the various scenarios might affect the environment. Scenario 1: Strengthening the Existing Regulatory-Utility Bargain. Not all electric utility industry executives are convinced that fundamental structural changes in the industry are needed or desirable. For the most part, these skeptics can be found among the utili ies who have done well in the existing system, and the crux of their assessment of the current business environment for electric utilities is that timeless bit of country wisdom: "If it ain't broke, don't fix it." The leader in this school of thought is American Electric 21
PAGE 170
Maize (H3-6585.0) Power, a large, successful utility holding company based in Columbus, Ohio. AEP has offered a proposal for what he calls "rolling prudence," which is a state-based system of periodic reviews of construction projects, in advance of financial commitments, and an end to major disallowances after a construction project is finished.34 AEP's views form the basis of the OTA scenario 1. In OTA's words, "Scenario 1 continues the existing regulatory scheme and electric power industry structure and reaffirms the regulatory-utility bargain with minor modifications of regulatory rules and procedures to improve the ability of utilities to attract capital for construction of new facilities and to assure a reasonable return to investors (e.g., "rolling prudence reviews"). Modifications of PURPA rules to correct perceived imbalances in avoided cost pricing rules for QF [PURPA qualifying facilities] power would also be allowed." As with all the visions of the future sketched by OTA, Scenario 1 is a mixed bag of environmental problems and opportunities. The environmental advantages flow from the fact that scenario 1 is well-understood. As essentially the status quo with slight modifications, the first scenario presents issues that have been faced in the past, and relies on institutional arrangements that have been developed over the past 20 years. 34. John Mccaughey, "Dick Disbrow: Dissenting With The Fashionable Utility Talk," Energy Daily, Nov. 23, 1987, p. 1. 22
PAGE 171
Maize (H3-6585.0) With this scenario, we basically know where we stand on environmental issues. The concept of "rolling prudence" also has some potential environmental benefits. It might prove easier to cancel some projects earlier in the construction process, before such enormous amounts of capital have been sunk in a project that cancellation becomes nigh on to unthinkable. Prudence is a doctrine that utility commissions have rediscovered recently, and applied with various effect. However, as New York Attorney General Robert Abrams observed, with regard to heavy disallowances for at Nine Mile Point 2 and Shoreham, "These findings of imprudence, salutary as they were, necessarily came too late to prevent vast expenditures which should never have been made."35 Utilities complain that the current system subjects them to too much risk, and there is merit in that complaint. But the current system also results in too many white elephants, where the high capital costs render lower operating costs meaningless unless the utility is willing to write off the sunk costs and a return on them. This has occurred time after time with new nuclear plants, such as Nine Mile Point 2, Shoreham, Diablo Canyon 1 & 2, and has even affected some coal-fired plants, such as Colstrip 3 and 4. Carefully designed, periodic prudence 35. Robert Abrams, op. cit. 23
PAGE 172
Maize (H3-6585.0) reviews could provide an institutional mechanism to prevent unneeded and environmentally-damaging plants from being built. The periodic reviews might also be a way to factor in technological advances made during the course of plant construction. Under the current system, once a plant design is finished, it is difficult to persuade the utility to alter it voluntarily to incorporate advances in pollution control technology. Reviews during the process might provide a way to update the plant plans and apply the best available technology. If rolling prudence were largely implemented on a state-bystate basis, there could be considerable variety in how the states put it together, much as there are significant differences in how particular states regulate electric utilities today, although most follow the same general model. Scenario 1 is not without environmental problems. It is not surprising that many of those who advocate it, such as AEP, managed to thrive during the lean years of the late 1970s and early 1980s. They did it by eschewing construction where possible and by keeping their existing plants on line. In AEP's case, many of those existing plants are the oldest, dirtiest coal-burning facilities in the Midwest that are the target of acid rain cleanup proposals. So the down side to the status quo, from an environmental standpoint, is represented by those older coal-fired plants. For 24
PAGE 173
Maize (H3-6585.0) example, Cleveland Electric Illuminating's Eastlake plant as a state emission limit of 5.64 pounds per million Btu and the Avon plant has a 4.65 pound limit, versus the new source performance standard of 1.2 pounds. Other older plants around the country have even higher emissions limits under State Implementation Plans.36 The 1970 Clean Air Act (as amended in 1977) was premised on the belief that plants would largely be scrapped after their 30-year book lifetime. Consequently, the act relies on the new source performance standards for its regulatory bite, rather than on pressing for improved environmental performance of existing plants. Unfortunately, the economic landscape in the years since Congress passed the Clean Air Act has favored keeping existing plants on line and avoiding building new ones. This was driven partly by the costs of pollution control on new plants, but more directly by unusually high interest rates of the 1970s, coupled with declining and unpredictable load growth. Powerplant lifeextension and geriatric programs have become a major focus of savvy utilities, and some experts believe that it may be possible to keep plants in service almost indefinitely.37 Under the Clean 36. Figures from Centerior Energy environmental department, interview on Apirl 18, 1988. 37. "Longer Life for Fossil Fuel Plants," EPRI Journal, July/August 1987, pp. 21-27. 25
PAGE 174
Maize (H3-6585.0) Air Act, if the cost of a life extension program exceeds 50 percent of a "comparable new facility," the plant may be subject to NSPS. According to the Electric Power Research Institute, "This regulation has not yet been tested, and utilities are unsure whether the 50 percent trigger refers only to one-time capital expenditure or to aggregated refurbishment costs over several years."38 The status quo offers a strong incentive for utilities to keep the oldest, and usually dirtiest, plants on line as long as possible. In extending the life of the existing plants, the utility avoids siting disputes, heavy capital requirements, and the Damoclean sword of prudency reviews and major disallowances. By contrast, some of the other scenarios might encourage utilities to close the facilities if they can get power cheaper from QFs or independent producers, can raise capital relatively inexpensively, or can avoid the need for prudency reviews and rate basing entirely by building a deregulated plant. Scenario 2: Expanding Transmission Access in the Existing Institutional Structure. This scenario basically opens up electric utility transmission lines to bulk power sellers and buyers. Under this 38. Ibid. p. 26. Also, the plant could be subject to NSPS if the emission rate of any of the criteria pollutants is increased as a result of the life extension program. 26 /ltJ
PAGE 175
Maize (H3-6585.0) scenario, in OTA's words, "Utilities and large retail customers can petition FERC for mandatory wheeling orders to nonlocal generators based on a new public interest standard." Just what that "public interest standard" would be is an important item, because it may be possible to build environmental elements and concepts into the standard. For example, it might further environmental goals to wheel in power from remote sites to avoid burning coal or oil in an urban enviornment. In this regard, it is important to note that neither Scenario 1 nor Scenario 2 mention the role that the regional power pools and the National Electric Reliability Council play in transmission planning, an important omission. The pools and NERC function together to advance at least quasi-public values, in that they were put together after the giant 1965 East Coast blackout, in an attempt to prevent future mishaps of that sort. They are, of course, creations of the utility industry and along, and share its perspective on the public interest. Should access to transmission expand beyond the traditional electric utilities, using some sort of public interest test, then the role of both the pools and NERC might be broadened, with an explicitly "public interest" mandate, and public participation beyond the utility industry itself. Presumably, the result of Scenario 2 would be greater use of transmission, particularly large, unconventional exchanges that 27 /~
PAGE 176
Maize (H3-6585.0) would be governed by contract provisions.39 As a result, utilities would have to plan for third-party transmission in their system planning for their power lines. The result likely would be plans for more transmission lines, with concomitant disputes. Some utilities might see transmission as a new business opportunity and build transmission marketing into their plans. From an environmental perspective, this scenario could have some favorable and some troubling consequences. On the positive side, greater wheeling could lead to construction of fewer baseload plants and a more flexible electric supply system, better able to to accommodate advanced renewable technologies such as photovoltaics.40 Greater wheeling and a full national grid could avoid situations such as today's power surplus in the South and Midwest while New England faces potential power shortages.41 But if expanding transmission access is 39. This sort of access to transmission could also stimulate the development of a futures market for electricity. Some of the more exotic OTA scenarios might also have this result. 40. A fully-connected grid could act like a storage system for sun-generated power, wheeling power west to east with the progress of the sun, helping to overcome one of the obstacles to photovoltaics. In mid-summer, there are only about four hours a night when the entire continental U.S. is dark. 41. For the conventional wisdom on New England's electric needs, see New Engalnd Governors Conference, "A Plan for Meeting New England's Electric Needs, Delcember 1986. For a powerful critique of that view, see New England Energy Policy Council, "Power to Spare: A Plan for Increasing New England's Competitiveness Through Energy Efficiency," July 1987. 28 11~
PAGE 177
Maize (H3-6585.0) successful, presumably more transmission capacity will be constructed. As noted earlier in this paper, siting, building, and operating electricity transmission has both well-understood and frontier environmental problems ranging from land use to public health issues associated with low frequency fields. Access to transmission might also encourage unneeded plant construction, both by IPPs and QFs. If electric utilities see selling transmission services as a business opportunity, rival utilities might get into price wars attempting to lure generators into their grid. That could lead to construction of plants beyond what would occur simply to supply the PURPA market if transmission continued to be closely guarded. Presumably, most of those plants would be gas-fired combustion turbines, with perhaps some combined-cycle generation as well (although Case Study 2: Bidding in Massachusetts: a Glimpse of the Future?,42 somewhat belies this). While natural gas is the cleanest-burning fossil fuel, it is not entirely devoid of pollutants. In non-attainment areas, increased generation could lead to further tension and disputes over pollution offsets and lowest achievable emission rates (LAER). In attainment areas, increased generation would consume some of the PSD increments available for other kinds of development. Greater access to transmission could also widen the 42 Discussed later in this paper, pp. 53-60. 29 /71
PAGE 178
Maize (H3-6585.0) opportunities for trash-to-energy projects. A shortage of suitable land disposal sites, and PURPA currently encourage these plants,43 and greater access to transmission and hence a broader market for the power, could stimulate them even more. That could lead to even greater contention over waste-to-energy projects at the local and national leve1.44 Greater access to transmission could also slow individual utility conservation and load management programs. Greater transmission access would complicate the analysis that goes into conservation and load management planning. It might become necessary to create regional conservation and load management institutions, such as the power pools and NERC, to match conservation and load management planning with regional transmission and generation planning. This is what has happened in the Pacific Northwest, as a result of the 1981 Northwest Power 43. NEESPLAN II, the New England Electric System's comprehensive business plan for the next 15 years, adopted in April 1985, foresees adding 180 megawatts of generating capacity from trash plants by the year 2000, out of a total projection of 500 megawatts coming from "alternate energy." NEESPLAN II also projects 70 megawatts from hydro, 175 from cogeneration, and 75 from miscellaneous sources such as solar and wind. At the time of the plan, NEES was already negotiating contracts from more than 85 megawatts of trash-to-energy in its service territory. See NEESPLAN II, pp. 39-40. 44. See Neil Seidman, "Garbage In, Garbage Out," Not Man Apart, November-December 1986, pp. 10-11, for an environmental critique of mass burn projects. The Institute for Local Self Reliance has a study of transmission and waste-to-energy projects currently underway. 30
PAGE 179
Maize (H3-6585.0) Planning Act. Scenario 3: Competition for New Bulk Power Supplies. This scenario is basically the Keystone and FERC Hesse proposal for all-source competitive bidding for generation. As OTA says, "Scenario 3 creates a two-tiered bulk power supply system: new power supplies under a minimally regulated, 'workably-competitive' market; and existing power generation remaining under current state-federal scheme of regulated entry and pricing. The electric power supply industry will gradually evolve to an all competitive generating sector as existing plants are replaced." From an environmental standpoint, there is probably more known about this scenario than some of the others, because more thought and effort has gone into it, at both the federal and state level. At least three states45 have either implemented bidding systems or are in the processing of implementing them, and FERC has issued a notice of proposed rulemaking on bidding for power. An environmental report done for FERC by Oak Ridge National Laboratory identified potentially significant enviromental impacts from the agency's proposed bidding regime, particularly increased use of coal in four states, New York, New 45. Maine, Massachusetts, and New York. 31
PAGE 180
Maize (H3-6585.0) Jersey, Virginia, and California.46 As a result, the FERC will perform a nationwide Environmental Impact Statement as part of its rulemaking, which should shed even more light on the environmental consequences of this scenario. The scenario offers some potential environmental benefits, chiefly the prospect of more rapid replacement of the older plants with new plants, which are likely to be less polluting. The scenario implicitly assumes that "new" power will eventually drive out "old" because new, "competitively-priced" generation will be cheaper and because old plants will be phased out on some actuarial basis. But if the guaranteed rate of return to the old plants, particularly those that are fully depreciated, exceeds the return on investment available in the competitive market, those assumptions may not hold, and old plants may continue to be a problem. One environmental issue will be whether and how to treat plant geriatric work in the context of bidding. If a utility is required to bid the added supply associated with a particularly life extension project, it starts with an asset owned by the ratepayers. Even if fully depreciated, the plant would still have a market value. If the market value of the plant isn't factored 46. "Environmental Report: Regulations Governing Bidding Programs (Docket No. RM88-S-OOO) and Regulations Governing Independent Power Producers (Docket No. RM88-4-000)," Oak Ridge National Laboratory, March 1988. 32 /?{-
PAGE 181
Maize (H3-6585.0) into the bid price, the utility could reap a windfall profit from the life extension, a further incentive to keep old plants on line. This is similar to the problem posed by a bidding scheme that allows a utility to spin off its P.xisting plant into a deregulated subsidiary and then bid the power from that plant against new construction in the power auction. In both cases, it is necessary to factor in the value of the existing asset in order to avoid subsidizing older, presumably dirtier, plants. Two other environmental issues are particularly pertinent to the concepts of all source bidding to supply utilities with power. The first is how to factor environmental considerations into the bidding process, and the second is how to square the bidding schemes, a supply-side issue, with conservation and load management, demand-side issues. The second issue may prove to be the most difficult to deal with, although not insurmountable. In the states that have addressed the bidding schemes so far, environmental issues generally have been treated as "nonprice" factors.47 Other non-price factors include such things as reliability, dispatchability, and fuel diversity. The difficulty with the non-price factors is that they introduce an element of subjectivity to the selection of the winning bidder, and take away from the auction aspects of the bidding process. That means 47. See testimony of Robert J. Keegan, Commissioner, Massachusetts Department of Public Utilities, before the Senate Energy and Natural Resources Committee, Feb. 4, 1988, p. 8. 33 17)
PAGE 182
Maize (H3-6585.0) there will continue to be a need for regulatory review to make sure that the subjective judgments of the utility don't adversely bias the decisions. It is also possible that the non-price factors will be given less emphasis than the more easily quantifiable price elements in the bids. In cases where there is a larger policy issue such as, for some, fuel diversity --the bidding process might have to be altered somewhat to reflect this. In New York, for example, Long Lake Energy Company, a hydro developer, suggested that, in view of the public policy in favor of developing renewable sources of energy, the state be required to have separate requests for proposal for renewable projects during the bidding. Otherwise, the company said, a capital-intensive project such as hydro might not be competitive on a price-only basis.48 Long Lakes may have raised an important issue, but it is important to note that "public policy" exemptions could be the beginning of a very slippery slope where one person's public policy issue is another's pork barrel. It is important in establishing a bidding scheme to assure that all the players --utilities, IPPs, and QFs --are required to meet the same environmental standards, and that those standards also be the highest. In its brief to the New York 48. ALJ Frank S. Robinson, Case 29409-Recommended Decision on Bidding, Avoided Cost Bidding, and Open Wheeling, p. 65. 34
PAGE 183
Maize (H3-6585.0) Public Service Commission on that state's bidding rulemaking, Orange & Rockland Utilities argued that "to hold utilities to higher environmental standards would provide IPPs with an unfair and possibly deceptive economic advantage: customers could be receiving an ostensible benefit in their utility bills, with a hidden cost to the state's environment."49 Building environmental concerns into the bidding process as a subjective factor at least provides a conceptual way to make sure that awards are environmentally sound. But building in conservation and load management is a far more problematic issue. So far, both New York, Massachusetts, and the FERC have ducked the issue. In New York, ALJ Robinson simply ruled that demand side management not be included in the bidding process,50 although the PSC staff had proposed "negawatt" bidding, in which a purveyor of conservation and load management could bid measures to reduce the utility's consumption by the proposed supply increment. Rejecting the concept of negawatt bidding, Robinson argued that the equivalence of demand reduction and supply addition "is imperfect .... One can scarcely envision a utility making massive payments to a host of negawatt bidders with respect to sales that are thusly rendered into non-sales, diminishing the utility's 49. Robinson, op. cit., p. 66. 50. Robinson, op. cit., p. 53. 35
PAGE 184
Maize (H3-6585.0) base of revenues from which to make such payments."51 However, there are ways to perfect the equivalence, according to Maine Public Utilities Commissioner David Moskovitz. He would tie a utility's rate of return to relative reductions in the average bills paid by residential customers, and to reductions in electricity use per square foot by commerical customers. Thus, the lost revenues from conservation which New York's Robinson noted would be offset by higher returns on the remaining business.52 In Massachusetts, the commonwealth did not include it in the first round of bidding, but h~s an inquiry underway that, among other things, examines how to include conservation and load management in the bidding process.53 Boston Edison officials believe that it is possible to include negawatt bidding in the commonwealth's bidding plan.54 The FERC's proposed rule on bidding under PURPA does not provide fnr bidding of conservation and load management. Economist Paul Joskow of the Massachusetts Institute of 51. Ibid. pp. 51-53. 52. Aviva Freudmann, "Moskovitz's Modest Proposal: Reward Utilities for Reducing Customers' Bills," Energy Daily, April 15, 1988, p. 1. 53. Interview with Henry Yoshimura, Massachusetts Department of Public Utilities, 12 January 1988. 54. Interview with John Whippen, Boston Edison Co., 21 January 1988. 36
PAGE 185
Maize (H3-6585.0) Technology has argued that FERC is correct to avoid the negawatt issue. Including demand-side options in the FERC proposal, Joskow told a congressional subcommittee, "could result in higher electricity rates, inequitable electricity rates, windfall profits for some conservation suppliers, and incentives for inefficient conservation investments." But Ralph Cavanagh of the Natural Resources Defense Council told the same committee that omitting demand side options from the rulernaking "would be to exclude from power supply competitions the least expensive resources available to modern electricity systems."55 Despite the objections, the negawatt concept is a powerful idea for stimulating energy conservation in a bidding regime. More analytic work, and perhaps some practical experiments, are needed to test whether the barriers that critics raise are real or fiction. Some suggest that negawatt bidding can work by targeting specific loads for reductions, such as motor efficiency, lighting, or buildings.56 Scenario 4: All Source Competition for All Bulk Power Supplies with Generation Segregated from Transmission and Distribution Services. 55. Dennis Wamsted, "Negawatts or Negafood? A Demand-Side Dichotomy," Energy Daily, April 4, 1988, p. 1. 56. Whippen, op. cit. 37 l I
PAGE 186
Maize (H3-6585.0) This scenario extends the concepts of Scenario 3 to their logical conclusion, the dis-integration of the heretofore vertically-integrated electric utility. The result is an industry that looks similar to the natural gas industry. As OTA describes this scenario: "Local distribution companies would be primarily responsible for securing adequate power supplies from competing suppliers. Transmission divisions or subsidiary companies would provide wheeling services for utilities under regulated rate schedules and could also act as power brokers linking local distribution companies with power suppliers. Distribution companies could obtain mandatory transmission orders from FERC on a public interest standard. There would be no mandatory wheeling for retail customers." Both Scenario 4 and Scenario 5 are considerably further from the status quo than any of the predecessors. Consequently, trying to divine their environmental impacts is a speculative enterprise at best. Nevertheless, several environmental questions present themselves with this full-fledged revolution in the electric utility industry. They are: the older plant problem, how to build in environmental analysis, and the problem of demand side management. Scenario 4 could present the most powerful incentives yet to continue using older, dirtier plants. The problem is identical to 38 If{ J-
PAGE 187
Maize (H3-6585.0) that described in Scenario 3 with regard to whether life extension projects can bid to supply generation on the same basis as IPPs and QFS. Scenario 4 answers that question and the answer is "yes." In that circumstance, utilities will doubtless argue that since their older plants are fully (or more fully) depreciated, they are the low-cost bidders, ignoring the market value that the plant possesses. The result is a powerful subsidy for the fullyamortized plant, even if a considerable amount is spent in lifeextension. This flies in the face of long-standing environmental goals, contained in statutes such as the Clean Air Act and the Clean Water Act, of replacing aging, more polluting plants with new, less polluting industrial plants. How to solve this problem? Clearly, regulators must structure the rules so that the market value of the existing plant and equipment gets recognized in the free-market price of power from that plant. After all, one can make a powerful argument that it is the public, in the form of the ratepayers, who own the plant, since they paid for it. One way to deal with this problem would be to force the nonderegulated generating spinoff to bid in a free auction against other generators for ownership of the plant. When a utility spins off a generating company, the utility would continue to own the generating asset, and then sell it to the highest bidder. 39
PAGE 188
Maize (H3-6585.0) One wrinkle on that proposal, made by Long Lake in the New York proceeding, would credit or debit the utility's rate base for any difference between the net book value of the asset and its sale price. The new owner would do the geriatric work and use the refurbished unit to enter the market.57 Another environmental obstacle this scenario presents is the familiar one of how to factor environmental analysis into the process. Again, this problem bears on the larger problem of how to get the older plants retired. If all plants are deregulated, those that have older, less sophisticated pollution control devices likely will have a cost advantage in bidding. A new plant, for example, would have to obtain site approval and a host of permits that would not burden the exiting plant. Additionally, a new plant sited in a non-attainment area would have to go over the costly LAER (lowest achievable emission rate) hurdle, obtain pollution offsets, and the like. In an attainment area, the new plant would have to go through the PSD process. An existing plant competing against those new plants could avoid any of those costs, as well as the high capital costs of scrubbers, bag houses, precipitators, and the like. It will require considerable regulatory ingenuity to figure out how to put the existing plant and new plants on an environmentally-level playing field in this scenario. 57. Robinson, op. cit., p. 55. 40
PAGE 189
Maize (H3-6585.0) Finally, there is the conundrum of how to carry on demand side management in an economic environment that is almost completely supply side (we will go the rest of the way with Scenario 5). In a non-integrated market, with generation separaced from transmission and distribution, it is not very clear just who will worry about conservation and reducing demand. The distribution companies or Discos will be less concerned, because they no longer face the risks of construction which have driven much industry concern about demand management. Discos will make money only if they sell power, not by saving. If the equivalence between demand reduction and supply addition is imperfect in Scenario 3, it is even less so in Scenario 4. The scenario would also reduce pressure on regulators to push for conservation and demand management, because they won't face the need to make ratebase decisions, with possible rate shock as a result. Clearly, the interest of the genco will be to generate and sell megawatts. Scenario 5: Common Carrier Transmission Services in a Disaggregated, Market-Oriented Electric Power Industry. This final OTA scenario completes the journey to deregulation begun in Scenario 1. All generation would be deregulated, with federal or state rate regulation of transmission, as a common carrier, and state regulation of 41 I~
PAGE 190
Maize (H3-6585.0) distribution. Transmission is done by separate transmission firms, acting as common carriers and charging tariff rates, presumably set by the FERC if the transaction crosses state boundaries and enters into interstate commerce. Wholesale and retail customers, gencos, IPPs, and QFs would all have guaranteed access to transmission at a known price. (In practical fact, the terms IPP and QF would no longer have any meaning. All generators are created equal in this scenario.) In addition to the environmental issues raised with regard to Scenario 4, this scenario has some unique environmental problem areas. The knotty issue of conservation and load management becomes even more intractable in a conventional sense. With transcos now in the market, making their money from selling transportation services, another force has been removed from the conservation and load management equation and added to the supply ledger. Now only the lowly, regulated disco --probably serving a captive and bypassed residential and small commercial market will have any incentive to push demand side measures. And as long as the disco can buy power cheap enough to make a reasonable rate of return on sales, all incentive for conservation and load management disappears. Scenario 5 also raises the specter of reduced maintenance of power generating equipment. In the rush to compete, particularly if the competition seriously drives down prices and profit 42
PAGE 191
Maize (H3-6585.0) margins, generating companies may decided to cut costs by skimping on maintenance. This can have disastrous environmental and health consequences. In this regard, the electric utility industry could come to resemble the deregulated U.S. airline industry, where the accident rate is soaring,58 perhaps as a result of cost-driven cutbacks in maintenance. This issue is not present in prior scenarios, because in each case, some strong institutional entity remains with a vested interest in reliability and maintenance. Even in Scenario 4, the integrated transmission-distribution company has a need for high reliability standards. But in Scenario 5, the only entity with an overriding interest in reliability appears to be the distribution company. For both the genco and the transco, reliability becomes solely an economic issue. If it makes more economic sense to walk away from a market than to continue to sell to it (as a result, for example, of a poorly structured fuel supply contract or a contract for transmission services that turns out to be uneconomic), the genco probably will walk. If the transco has an obligation to provide transmission service, the company might meet that obligation in the cheapest and most grudging fashion. Potentially, this could recreate the circumstances of the 58 Laura Parker, "Airline Accident Rate is Highest in 13 Years," Washington Post, December?, 1987. 43 Ill
PAGE 192
Maize (H3-6585.0) railroad industry prior to the 4R Ac~ and the Staggers Rail Act, where rail maintenance was so bad the industry created a new term, "standing derailment," to describe the phenomenon of rail cars that fell over while standing still. There also is fear is that the disco is a weak sister, bypassed by its biggest customers and left serving only a market that is economically fragmented but politically very powerful (i.e., a market that use its political power to keep its rates low). In those circumstances, the disco may not have enough clout to insist that its suppliers maintain their plants even under adverse economic conditions. Finally, the sort of industry structure envisioned in Scenario 5 should result in a construction boom for new transmission. Given the ferocity of local siting battles in the past, the result could well be political gridlock. Going further, it seems clear that Scenario 5 can only come to pass if a way is found to site, construct, and operate power lines with a minimum of disruption and delay. Given the siting issues, which are being addressed for OTA in another report, and the health issues, also addressed in another report, believing that this scenario can ever happen requires considerable credulity. V. CASE STUDIES 44 /(f
PAGE 193
Maize (H3-6585.0) Case studies in two particular areas can serve to illuminate some of the issues raised in the discussion of the scenarios. Thus, they serve as a sort of reality check on what may be pure speculation about the scenarios. In the first case study, the focus is transmission, specifically a series of tangled, emotional, and expensive disputes about power line siting. It serves to illustrate the passion and difficulties that accompany the environmental issues surrounding where to build power transmission facilities. Until the kinds of issues that led to the difficulties in the cases sited are resolved, it will be difficult indeed to make a transition to a future electric utility industry that requires considerably increased transmission. The second case study looks at the experience of the Commonwealth of Massachusetts in implementing competitive bidding for new supply under the terms of PURPA. It should help illuminate some of the issues that will face other states if they wish to implement bidding schemes, and should point to some areas at the FERC may want to deal with as it responds to comments on its proposed rulemakings. 1. The Transmission Quagmire: The New York Power Lines Project, Colstrip, Coal Creek, and Klein Independent School District. In 1973, the New York Power Authority applied to the state Public Service Commission for a Certificate of Environmental 45 If?
PAGE 194
Maize (H3-6585.0) Compatibility and Public Need for a 765 kV transmission line from the Canadian border near Massena to Utica. The total distance is about 155 miles. The certificate from the PSC is a one-stop permit. Once granted, it eliminates the need for any local or any further state permits. The next year, Rochester Gas and Electric and Niagara Mohawk Power Co~p. applied for a certificate for a second 765 kV line, this one running 66 miles from Rochester to Oswego.59 When the required public hearings began, it became clear that this would not be a routine siting decision. The public was avid to testify, and raised issues related to audible noise, land use, and, most troubling, biological effects. The administrative law judges in the two cases, trying to avoid duplicative testimony, ordered a common set of hearings for the two power lines. The hearings on the common issues related to the two power lines took four years, heard 31 expert witnesses, and produced more than 14,000 pages of testimony. Most of that testimony concerned the potential for 0iological effects from electric and magnetic fields. 59. For accounts of the New lark case, see Daniel A. Dri8coll, "Standard-setting in the United States: A View from New York," paper presented at the International Utility Symposium on Health Effects of Electric and Magnetic Fields, September 16-19, 19 8 6. Also, "EMF: The Debate on Heal th Effects, ,r EPRI Journal, October/November 1987, pp. 4-15. 46
PAGE 195
Maize (H3-6585.0) A bombshell in the hearings came when information surfaced of Soviet studies done 10 years earlier. The Soviets were investigating symptoms of appetite loss, headaches, fatigue, and insomnia on the part of switchyard workers. The Soviet research concluded that there are biological effects caused by low frequency fields. The Public Service Commission ruled that in face of the Soviet studies, it had "no alternative but to presume that a biological effect is hazardous until it is proven otherwise." The PSC said that doubts of the hazardous nature of the biological effect can influence the degree of caution that is required, but that it can't be ignored simply on the grounds that it hasn't been proven a menace. The PSC eventually approved the two 765 kV lines in 1978, but with regulatory constraints. The commission ruled that residences could not be permitted within 175 feet of the centerline of the Power Authority's 765 kV line, limiting residential electric field exposure to less than 1.6 kV/m. According to Driscoll, the effect of this is that the field from the 765 kV line is not greater than that produced by 345kV lines at the edges of their rights-of-way. "In this way," Driscoll said, ""the commission assured that the risks, if any, of long-term exposure to transmission line electric fields would be no greater than those, which society 47 /~!
PAGE 196
Maize (H3-6585.0) implicitly accepts, of long-term exposure to the 345 kV lines operating th~oughout the state."60 The PSC also ordered a $5 million research program, the New York State Power Lines Project, to investigate the potential health hazards of power lines. The commission then pegged its restrictions on the 765 kV lines to the findings of the project. "In effect," said Driscoll, "the Commission declared a moratorium on higher fields until the results of the New York State Power Lines Project could be evaluated.1161 The Power Lines Project issued its final report in July, 1987. Earlier in the year, in February, researchers David Savitz, Howard Wachtel, and Frank Barnes released a study, sponsored by the New York project, finding a modest statistical correlation between childhood cancers and magnetic fields. According to Savitz, "There is no solid evidence that people should be worried, even if they live under a power line. The bottom line is that the evidence falls short of proving that electric or magnetic fields are a health hazard. On the other hand, questions have been raised th~t haven't been answered. So for a public health perspective, there is a reason for concern.1162 6 0 Ibid. p. 3 61. Ibid. 62. Quoted in a September 4, 1987 EPRI memo to its Advisory Council members, p. 2. 48
PAGE 197
Maize (H3-6585.0) The Savitz research buttresses a 1979 study by Nancy Wertheimer and Ed Leeper, and is causing considerable anxiety in the utility industry. EPRI has formed a 15-mernber panel of experts, headed by Gilbert Ommen, dean of the School of Public Health at the University of Washington, to review the EPRI research program on health effects in light of the emerging evidence that fields have biological effects.63 The emerging evidence on health effects is likely to make transmission line disputes all the more contentious and difficult. And the New York dispute was far from the most difficult of those that have been waged in the U.S. in recent years. Colstrip In Montana, for example, a dispute over building two 700-megawatt plants in the eastern coal fields of the state eventually turned into a nasty dispute over transmission. The project, announced in 1971 as a joint venture involving Montana Power Co., Puget Sound Power and Light, Portland General Electric, the Washington Water Power Co.,a and Pacific Power & Light, planned the two new Colstrip Units (units 3 and 4), and two new parallel S00kV lines from Colstrip to the Bonneville 63. Ibid. 49 /~
PAGE 198
Maize (H3-6585.0) Power Administration system in western Montana.64 The Colstrip project, of course, has a solid place in modern electric utility history for a variety of reasons. The plants, which ultimately turned out to be largely unnecessary, led to the formation of a powerful environmental movement in the West, the Western Organization of Resource Councils. The Colstrip dispute also provided an important chapter in the story of the rise of prudence reviews. But Colstrip also made its mark in the annals of transmission disputes. Eventually the power lines were built, 12 to 15 years after first announced. The project, which crossed public and private land and Indian land, required a full-scale, federal Environmental Impact Statement, seemingly endless hearings, and ~n enormous record that fills several feet of bookshelf. For the most part, the dispute centered on health effects, and the public evinced considerable skepticism about claims that power lines are safe. In the words of a BPA official, "It was very difficult to gain the confidence of the public relative to the biological effects issue. I think many of them automatically distrusted any entity of the Federal Government telling them that 3omething was safe. I believe this is primarily based upon other situations involving hazardous waste dumps, the 6 4 See George Eskridge, "Colstrip Transmission Project," paper presented at the International Utility Symposium on Health Effects of Electric and Magnetic Fields, September 16-19, 1986. 50
PAGE 199
Maize (H3-6585.0) Love Canal issue, and other areas of controversy over health issues involving the Federal Government."65 BPA's difficulties with the Colstrip line led Montana to adopt an innovative approach to power line regulation, which is done through the state's Major Facility Siting Act. Montana hired Dr. Asher Sheppard, one of the leading researchers in the field, to help the state set rules for exposure and mounted an administrative rulemaking process involving extensive hearings. As a result of Sheppard's recommendations and the public record, the state adopted a conservative standard for electric fields, tougher even than New York's. The state prohibits the electric field at the edge of right-of-way for new facilities from exceeding 1 kV/m measured one meter above the ground in residential or subdivided areas. The field at road crossings under the line cannot exceed 7 kV/mat one meter.66 An interesting aspect of the Montana rules is that affected landowners can waive the 1 kV/m standard across their property. Subsequent landowners have to live with the previous landowner!s waiver. According to a Montana official, "The state feels that it is appropriate for landowners to participate in making decisions that affect their personal land-use objectives and possibly their 65 Ibid. p. 9. 66. Van Jamison, "Regulating Emissions in Montana," paper presented at the International Utility Symposium of Health Effects of Electric and Magnetic Fields," September 16-19, 1986. 51 / /9J l
PAGE 200
Maize (H3-6585.0) health. Science has not provided any definitive answer to the question of the risk associated with living or working very close to a major energy transmission facility. Montana's standard permits affected landowners to judge what is an acceptable risk for them." 6 7 Coal Creek The processes in both New York and Montana were orderly compared to what happened in Minnesota when two cooperatives, Cooperative Power Association and United Power Association, announced a two-unit, 1,100 megawatt mine-mouth lignite-burning plant near Underwood, N.D., along with a 436-mile ~400kV highvoltage, direct-current line from the state to west of Minneapolis, and two ac lines to move the power into the existing transmission system. The problem was the 177-mile section of the HVDC line in Minnesota, which crossed eight counties and required easements in 476 parcels of land. Licensing required 15 months and three separate state permits. Each permit required a full set of hearings, meetings, and deliberations by citizen committees. The project also had to prepared a full-scale Environmental Impact Statement. The Coal Creek HVDC line got its final permit in June 67. Ibid., p.4. 52
PAGE 201
Maize (H3-6585.0) 1976 and construction began in October 1977.68 Opponents of the project, drawing on the Russian research and the New York controversy, focused on the health issue. Before issuing the final permits, the Minnesota Environmental Quality Board commissioned several studies of health effects, culminating in a report by the Minnesota Department of Health finding no health problems. But as a United Power Association official said, "The MDH report did nothing to lessen the controversy because: in 1977, opposition to the line was in the ascendancy; the report was prepared without public involvement and therefore was viewed as suspect; and the MEQB did not place any emphasis on the report's fi~dings." According to critics, the state's heavyhanded approach to the issue may well have exacerbated the dispute and energized its opponents.69 Despite the MOH report and MEQB license, controversy over the line escalated, particularly in two counties, resulting in violence and vandalism during the construction. Through 1983, protesters had toppled a total of 16 steel transmission towers, at a replacement cost of $1.5 million. Replacement power and lost 68. Dan McConnon, "Health Effects from HVDC Transmission Lines: Resolution of the Minnesota Controversy," paper presented at the International Utility Symposi11m on Health Effects of Electric and Magnetic Fields, September 16-19, 1986. 69. For a harsh appraisal of the project and the state actions, see Wendell G. Bradley, "A Preliminary Cost Appraisal of the Coal Creek Project," in Lines Across the Land, Environmental Policy Institute, 1979, pp. 474-486. 53
PAGE 202
Maize (H3-6585.0) revenue costs exceeded $1.5 million. Opponents destroyed some 9,000 insulators, at a cost of $700,000. Sabotage of construction equipment totaled $300,000 in damages. Extra security costs amounted to about $4.8 million. Total cost of vandalism: more than $8.5 million.70 Klein Independent Dchool District In Texas, courts did more damage than vandals to a power line project, fining Houston Lighting & Power $25 million in punitive damages in 1985, and forcing the utility to move an already-constructed power line. The case is still in litigation, as HL&P attempts to overturn the fine.71 In 1980, the utility wanted a new 345kV line, and proceeded to condemn property and build the facility, with no opposition. Part of the line passed over land owned by the Klein Independent School District. After the line was already in place, the school district built a new school under the power line. At the same time, the school district sued the utility, arguing that the condemnation proceeding was flawed. In 1985, the case went to trial before a six-person jury. At 70. McConnon, op. cit. 71. "Evolution of an Issue," EPRI Journal, October/November 1 9 8 7 pp 1 0 -11 54 l!f
PAGE 203
Maize (H3-6585.0) that point, the school district first broached the health effects issue, charging that HL&P had "grossly abused its discretion" by putting a health risk on school property. The jury heard six expert witnesses on the health effects issue, four for the school district and two from the utility. The jury found heavily for the school district. The jury awarded the district $104,000 plus interest in actual damages, $25 million in punitive damages, and told the utility to restrict use of the line to emergencies outside of school hours, pending appeal. Ultimately, HL&P mooted most of the issues, by moving a 2.5 mile segment of the line around the school property. But in the meantime, the utility lost the use of the line for two years. The utility continues to try to overturn the punitive award. "As the HL&P case reveals," commented EPRI Journal, "the field effects issue is far from being resolved. Investigators have not yet been able to satisfactorily address the key uncertainties, and the legal debates continue in the absence of sound scientific evidence." 2. Bidding in Massachusetts: A Glimpse of the Future? Massachusetts appears to have gone farther than any other state in implementing a bidding scheme for allocating generation under PURPA. The commonwealth issued its first set of regulations 55 /If
PAGE 204
Maize (H3-6585.0) in late 1986 and the first contracts under the bidding scheme should be formally awarded soon. The state and its utilities are now working on a second round of bidding, with somewhat changed circumstances.72 The bidding process begins with the supply and demand files for each utility that are supplied to the state's Facility Siting Council. On the basis of that plan, the utility forecasts what its next supply addition will be. If, for example, the utility were to conclude that it's next piece of generation would be a 200-megawatt combined-cycle facility, then the utility would attempt to solicit 200 megawatts of supply from QFs, to avoid that new facility. The Massachusetts regulations stipulate how to calculate the costs of the new generating capacity, including system fuel costs and capital costs. That determination, which is the equivalent to the avoided cost, becomes the ceiling price for the bidding process. In other words, the avoided cost becomes the maximum that the utility will pay to QFs. The Massachusetts program works with a standard contract, developed by the DPU, against which the suppliers are to bid. The 72. Much of this case study is based on interviews with Henry Yoshimura of the Massachusetts Department of Public Utilities, who was the author of most of the bidding regulations, and John Whippen, manager of energy resource planning and forecasting, Boston Edison Co., who is in charge of the project for Boston Edison. 56
PAGE 205
Maize (H3-6585.0) utility can include "non-price" elements in its solicitation and bid-evaluation process. This is where the utility can build in environmental constraints, or other issues such as reliability, dispatchability, fuel diversity, or the like. The standard contract provides a baseline, but the final contract does allow for negotiation, as long as the DPU is able to exercise oversight. The current bid system does not include provisions for conservation and load management. That thorny issues, along with the issue of how to treat non-QF facilities, is currently the focus of another regulatory proceeding, which is underway at the DPU. It is important to note that Massachusetts already requires wheeling within the state, on the basis of an open, published tariff. If a QF in the western part of the state wins an award from Boston Edison, state regulations require the intervening utilities to wheel the power, basically as common carriers. The Experience To Date So far, Boston Edison Co. is the only utility to have completed the full cycle from the first RFP. The company hopes to have contracts signed soon, for 344 megawatts of power in nine separate projects. Boston Edison was seeking only 200 megawatts, and got bids for 1,860 megawatts. The levelized ceiling price for the bid was 57
PAGE 206
Maize (H3-6585.0) 8.7 cents per kilowatt hour, and the successful bids came in at between 6 and 6.5 cents. The reason Boston Edison is awarding contracts for 344 megawatts is that the first eight low bidders came in at a total of 144 megawatts, but the ninth bidder offered 200 megawatts. After some negotiations among the parties, Massachusetts DPU concluded that Boston Edison could go forward with the nine bidders. Massachusetts examined California's experience with its Standard Offer No. 4, where as many as a third of the bidders turned out to be speculative projects that likely never would have been built. In order to prevent that, Massachusetts' regulations require that the QF put up a $15 per kilowatt deposit at the contract signing, as earnest money. Environmental Issues From an environmental standpoint, the projects that Boston Edison has selectea do not inspire great confidence that bidding will result in a better fuel mix or greater environmental protection than conventional avoided cost determinations. (See list below.) Project FHN Energy (w/Dominion Resources) Size 200 rnw 58 Technology coal-AFB
PAGE 207
Maize (H3-6585.0) Clean Harbors Bellingham NEES-cogen NEES-cogen NEES-cogen NEES-cogen Webster Resource Wheelabrator Energy System 2.5 mw 68 mw 3.3 mw 3.3 mw 24.5 mw 10 mw 7 .4 mw 25 mw 344 (total) hazardous waste gas-combined cycle combustion turbine combustion turbine gas-combined cycle gas-combined cycle trash-mass burn construction debris (aka. urban woods) Several things are troubling about the successful bidders for the Boston Edison contracts. First, the 200 megawatt coalfired facility belies the widely-shared expectation that gas would be the preferred fuel for QFs and IPPs. It is also important to note that the original bid for the 200-megawatt atmospheric fluidized bed facility proposed a site in East Boston, a small, highly-urbanized area. Subsequently, the project developers have decided that perhaps an inner-city site wasn't such a good idea, and have proposed two alternative sites for the project. Also troubling are the waste-to-energy plants, particularly the Clean Harbors project. That project plans to burn hazardous wastes in a rotary kiln, raise steam, and sell power to Boston Edison. Whether this project will ever oe licensed is clearly a 59
PAGE 208
Maize (H3-6585.0) legitimate question. The Webster mass burn facility is already running into the predictable siting disputes, which threaten to derail or delay the project. The Wheelabrator project is one of several "urban woods" schemes to burn construction wastes. Construction wastes would appear to offer a higher-quality fuel stream than the conventional mixed trash. It might also be a cleaner waste stream, although one could postulate some environmental problems with construction trash, particularly with air emissions and ash toxicity from burning lumber treated to resist termites. Another problem could be associated with the amount of gypsum wallboard in the waste stream. Burning gypsum could cause serious sulfur dioxide problems. There is an interesting irony in the four NEES cogeneration projects. While NEES has been among the utilities that have been pushing the FERC to embark on an all sources bidding scheme, 73 the company has been less enamored of bidding at home, at least as a purchaser of QF power. NEES argued in the Massachusetts proceeding that it could get more power, cheaper by negotiated contract rather than open bidding. The DPU gave the company an exemption from its bidding procedures in return for NEES agreements on more stringent wheeling procedures, and to a 73. Bill Rankin, "FERC Competitive Bidding Plan Splits The Utility Industry," Energy Daily, Sept. 9, 1987, p. 1. 60
PAGE 209
Maize (H3-6585.0) provision that the company must demonstrate that it obtains more power for less money by negotiations. Thus DPU and other utility officials were surprised when NEES was a major bidder for the Boston Edison contract. The technological mix that resulted from the first Boston Edison RFP was probably a result of bonus points the company awarded in the non-price section for fuel diversity. "We had established certain objectives we wanted to pursue" in the first RFP, said a Boston Edison officia174. "That included the promotion of fuel diversity." Boston Edison plans to revise its RFP over the next few months, to match an updated resource plan. The company expects to file RFP No. 2 with the DPU in March. While the RFP will be "philosophically" the same, it will be less price intensive, and push several non-price issues. Anticipating regulatory changes75, Boston Edison likely will push environmental performance by provide target pollutant 74. Whippen, op. cit. 75. Massachusetts in 1985 passed an acid rain control law that will require substantial sulfur dioxide emission reductions by 1995. The law requires an average emission rate of all facilities in the state of less than 1.2 pounds of SO2 per million Btu. New England Power, the NEES generating subsidiary, expects that it will have to reduce emissions from its Massachusetts facilities by as much as 46,000 tons per year. New England Power Fact Sheet, "Using Natural Gas at New England Power Company's Brayton Point State to Meet Massachusetts Acid Rain Law Requirements," January 18, 1988. 61
PAGE 210
Maize (H3-6585.0) levels, with a bonus for commitments by bidders to exceed those targets. The RFP, for example, might specify a 1.2 pounds per million Btu standard for 502 emission, and give a bonus for a commitment to exceed by 110 percent. Boston Edison is also pondering how to build conservation and load management bids into the RFP, probably by targeting specific loads the utility wants to reduce. Utility planners hope to have some version of a negawatt bidding system in place. Other Massachusetts utilities are not as far down the bidding road as Boston Edison. The DPU has approved the following supply additions, and ceiling prices, for the participating utilities: Cambridge Electric Light Co. 33 mw 7.33 cents per kwh Commonwealth Electric 76 mw 6.52 cents per kwh Eastern Edison 30 mw 6.86 cents per kwh Fitchberg Gas & Electric 11.7 mw 7.69 cents per kwh Nantucket Electric76 3.6 mw 7.8 cents per kwh Western Massachusetts Elec. 40 mw 5.8 cents per kwh Clearly, capacity bidding in Massachusetts has not proceeded far enough yet to make any firm conclusions about how it is working from an environmental standpoint. However, the first 76. Nantucket Electric supplies Nantucket Island and is not connected into the Massachusetts grid. 62
PAGE 211
Maize (H3-6585.0) Boston Edison bids have some troubling aspects, because of the unexpected presence of a large coal-fired plant and the proliferation of waste-to-energy projects. The second round of bids, driven by tough new pollution rules, could be better. It will be worth watching what goes on in Massachusetts as a harbinger of what might occur as a result of the FERC bidding initiative. VI. CONCLUSIONS Change is a given in the electric utility industry, and most observers would agree on the general direction of that change: toward greater deregulation of generation and away from the traditional pattern of the vertically-integrated electric utility. But as those changes appear, it will be important to keep an eye on the environmental impacts of the changed circumstances and conditions in the industry. None of the scenarios outlined by OTA are inherently incompatible with national environmental objectives. Nor are any of the scenarios inherently preferable on environmental grounds-at least, given our current level of understanding. However, as each scenario diverges further from the status quo than its predecessor, assessing environmental consequences become increasingly difficult and problematic. 63
PAGE 212
Maize (H3-6585.0) In all cases, environmental analysis must be an integral component of the policy making that will accompany the changes in the electric utility industry. It is neither desirable, nor practical, for advocates of the particular changes in circumstances --such as freer wheeling or decoupling generation from rate regulation --to assume that what they propose is environmentally neutral or benign. It is also important when considering environmental impacts to be mindful of Murphy's Laws and the doctrine of unintended consequences. What can go wrong, will. The planned will not occur as planned, and the unplanned will occur. 64
PAGE 213
OTA WORKING PAPER ECONOMIC AND PLANNING IMPLICATIONS OF THE FERC NOTICE OF PROPOSED RULEMAKINGS ON INDEPENDENT POWER PRODUCERS: A REVIEW OF DOCUMENTATION By The Ener1y Center Univenity of Pennsylvania This is a DRAFr OTA Workin1 Paper. It is bein1 circulated for review only and should not be quoted, reproduced, or distributed. The conclusions expressed in this report are those of the authors and do not necessarily represent the views of OT A. This report has not been reviewed or approved by the Technoloay Assessment Board.
PAGE 214
IITIODUCTIOI ECO~OMIC AND PLANNING IMPLICATIONS OF THE FERC NOTICE OF PROPOSED RULINGS ON INDEPENDENT POWER PRODUCERS: A REVIEW OF DOCUMENTATION by The Ener1y Center Unfversfty of Penn1ylvania The Federal Energy Regulatory Coaaission (FERC) has rele11ed three Notfces of Proposed Rules (NOPRs) for cont by concerned p1rtfe1. These three NOPRs address the issue of a change in 1tructure of the electric power industry and the implications these changes might have for competitors within the industry. The three NOPRs are entitled: (1) Regulation, Governing Independent Power Producers (IPP NOPR) (2) Regulations Governing lidding Progra (lidding NOPR) and (3) Admfnlstratfve Deterination of Full Avoided Co1t1, Sales of Power to Qualifying F1cilftfes, and Interconnection Facilities CADFAC NOPR). This report evaluates some of the economic implications (for utility planning and operations only) of increased competition in the electric utility sector identified in I review of selected documents submitted to FERC commenting on the proposed rulings (see Table 1). The review also includes 1rguents made by FERC in the NOPR's, as well as the dissenting opinions of Commissioner Trabandtft (Appendix A includes summary tables of the reviews of the documents) The report organizes the impact of the proposed rules into two basic categories: impacts on planning and impacts on 1 ~JO
PAGE 215
operation,. Under the fmpacts of planning, so of the possible subcategories are: Syste Reserve Margins Con1truction Leadtiaes Fuel Mix and Technology Choice Con1tructfon and Ffnancln1 Co1t1 Overall Syst Relfabflfty Sftfng of Plants The ipact1 on operation of utilities include the following subcategories: Coat of Coordinating Equipent Effect on Econofc Dispatch Operating Efficiency Operating Reliability Effect on Transais1ion Requirements Effect on Power Pool Agreements The University of Pennsylvania evaluation found a wide variety of perpesctives on the possible impacts of the NOPR rules. Generally, the contors did not provide strong and/or detailed evidence to support thefr respective vfews. There does not appear to have been any published rigorous attempt to exaine the impacts these wfll have on operations. Both the FERC NOPR documents and the-dissenting opinion by Comaissioner Trabandt cite studies which quantitatively assess possible impacts indirectly by analyzing related issues, but the issues addressed here, in many cases, have not been assessed directly. This report first summarizes the intent of the NOPRs and then assesses the impacts mentioned fn the NOPRs and the other documents. In the NOPRs, the commission presents 'benefits' and 'concerns' about the proposals. The summaries included here will be presented in the same format. 2
PAGE 216
TABLE 1: NOPR COMMENTS REVIEWED 1. American Paper Institute, (API) 2. American Public Power Association (APPA) 3. Con1uer Federation of America and Environmental Action Foundation (CFA & EA) 4. Cogeneratlon and Independent Power Coalition of Aaerlca, Inc. CCIPCA) 5. Edison Electric Institute (EEJ) 6. Electricity Con1uaer1 Resources Council, Coapetftlve Electric Power Alliance, Council of Industrial Boiler Owners (ELCON, CEPA, & CJIO) 1. Fourty Utilities (40 wTIL) a. Maryland People' Counsel (MPC) 9. National Association of Regulatory Utility Cof1sfoners (NARUC) 10. National Association of State Utility Conauaer Advocates (NASUCA) 11. North Aaerfcan Electric Reliability Council (NERC) 12. Nacfonal Independent Energy Producers (NIEP) 13. Consumer Owned Systems and National Rural Electric Cooperative A11oci1tion (NRECA) 14. Publfc Service Coaai11fon of Maryland (PSCOM) 15. State of Mafne Public Utflftfe1 Col11fon (SOMPUC) 16. Utflfty Working Group (UWG) 3
PAGE 217
STIEANLIIED IEGULATIOIS FOi INDEPEIDEIT POWEi PIODUCEIS: IATIOIALE The ethod and r1tfonale proposed by FERC for 1tre1alfnfng regulation applicable to IPPs fs described on pages 1 and 2 of the IPP NOPR document: The Federal Energy Regulatory Comfssion (Cof11ion) fa proposfng to 1treaallne regulation of a cl111 of non traditional utflfty suppliers, called Independent power producers (IPPs). The proposed regulations would: (1) authorize rates for IPPs to be determined through co petitlve bidding or rate negotiation subject to I price cap, thereby freeing IPP1 fro co1tb11ed ratkin1 while ensuring rates fall within a zone of reasonable ness; (2) authorize IPPs to file rate schedules wfth out having to provide extensive cost support; (3) Pt fro cost-related accounting, reporting, and record keeping requireents; (4) stre1aline the corporate and financial regulation of IPPs; (5) provide for virtually automatic authorizations to engage fn certain corporate activities; (6) revise filing fees; (1) waive annual charges; and (8) adopt an advance certification pro cedure to qualify 1s 1n IPP. By promul11tfng these regulations the Cofs1lon seeks to Iner supply options fn the wholesale electric energy arket and thereby fulfill ft1 statutory responsfbllftle1 under the Federal Power Act (FPA) and Publfc Utility Regula tory Policies Act of 1978 (PURPA). FERC proposed the streallned regulations bec1u1e of problems in the electric utility Industry. Several probleMs have plagued the industry since 1970. First, load growth was lower than predicted, and the utilities were caught with excess capacity. In addition 10 capital expenditures were granted less than full recovery by regulators. Thus, FERC asserts, many utilities have adopted a risk minimization strategy towards building new capacity. FERC suggests that the result of this rfsk averse strategy by the utilities may be the building of less capital-intensive and less technologically innovative capacity. This will hinder development of new technologies and lead to inadequate supplies 4
PAGE 218
of electricity. ,1n1lly, FEIC notes that predfctlons of the needed capacity In the next decade vary widely. This factor In cobfnatfon wfth the rfsk ainfafzatlon factor lead to uncertainty about future supply and capacity. Due to the uncertainty fn supply, FERC has proposed streaalfned regulations to proaote 1ddftfonal sources of supply through competition (IPP NOPR, P. 10). FERC fs concerned that utflftfe1 ay be unprepared should a supply 1horta1 occur in the 199011. The coi11ion believes that current regulations Inhibit Investments and that there fs a need to create an environment which encourages investments to ensure th investments will be made in I timely aanner. On the other hand, Commissioner Trabandt and other commenters do not believe that there fs sufficient evidence to warrant the NOPR1. While Comaissloner Trabandt agrees that the Issues of avoided cost and bidding need to be discussed, he disagrees with the need for discussing the generic deregulation of IPPs (Trabandt Dissenting comments P. 3 & P. 10). The disagreement stems from the question of whether new capacity will be needed, and ff this capacity would be available without the new regulations. The comassion asserts that: The recent event1 r1lse serious concerns about the future reliability and cost of electricity obtained exclusively under traditional forms of regulations. If these concerns are realized, there could be serious consequences to the nations economy CIPP NOPR p.17) To support the opposing view, Commissioner Tr1bandt refers to sources which state that no additional capacity will be made available from the NOPRs and that adequate capacity will exist: 5
PAGE 219
Av1fl1ble evidence fro11-all 1ectors indfc1te that those assertions [that new rules are needed for adequate supply of new capacity] are 1fply false and that needed new capacfty, fncludfng capacity fro11 IPP's, fs being acquired by electric utflftfes across the nation today under xistina regulation. (Tr1b1ndt dissent p. 28). The question of whether there will be adequate supply fn the late 199011 is the fundaaental concern, and ft strikes at the overfdfng reason FERC has gfven for providing the NOPR restructuring. The evidence cited by both parties however, 11 conflfctfng and there f1 no clear answer. ,eRc also proposed the stre111lfned regulations because of the burden of costofservfce re1ul1tfon1 on IPPs. The co1111f1sfon believes that thfs regulation creates dfsfncentfves for investment in IPP's. Investment is hindered because innovative technologies are ded to be riskier than technolo1fe1 fro11 ore tr1dftfon1l sources of supply and because risks often outweigh the gains to the IPP. Costofservfce regulations were originally 1i11ed at the utilities and w11 put into place to protect the public from abuses from monopolistic market power. Since ft is assumed that IPPs lack significant market and monopolostic power, FERC proposes that the regulatory protection of public Interests afforded by cost-of-service regulation is not warranted. (IPP NOPR, P. 22). NEW DEFINITION OF INDEPENDENT POWER PRODUCERS Until this point, the term Independent Power Producer (IPP) has been used to categorize group of nontraditional utility suppliers. FERC's initial definition of an IPP is also a broad conceptual definition. FERC further refines its criteria for an 6
PAGE 220
IPP fn the IPP NOPR. Definitions whfch repre1ent the evolution of FERC'I IPP crfterfa are quoted below (IPP NOPR, P. 30-34): IPP (CONCEPTUAL): a generating entity Cother than a QF) that fl unaffiliated with the franchised utility in the area fn whfch the IPP f1 selling power and that for other reasons lack 1ignificant aarket power. MARKET POWER: the abflity to Influence the price that cu1to er1 fn a particular 1re1 ut pay for a product. SIGNIFICANT MARKET POWER: the ability to set and aaintain I price in exce11 of the cost of coapetftfvely supplied generation. COST OF COMPETITIVELY SUPPLIED GENERATION: reflects the mfniu cost available to a buyer with substantial supply options. IPP (NARROW): the Coamission tentatively concludes that a seller is not likely to po111ss significant market power over a wholesale cu1toer when it sells power fro a plant not subject to costofservfce regu lation to a cu1toer that: (1) f1 not located in a retail service franchise territory po11111ed by the seller (or any of its affflf1tes), and (2) fs not served by transission facilities that are essential to the customer and that are controlled by the seller (or any affilf ate of the seller). To implement this 'bright line rule,' the ComMission proposes to define two terms: indepen dent power facility CIPF) and independent power producer CIPP). And IPF would be a facility (or portion of a facility) that is not in any utility's wholesale or retail rate bast and not otherwise afforded the regulatory assurances of cost recovery under cost-of-service regulation. This new definition of IPP's fs the first part of the proposed rulings made in the NOPRs. These definitions provide the basis for the other major ruling which is related to a bidding process for new generation designed to foster coMpetition for generation of electric power. 7
PAGE 221
IEGULATIOIS REGARDING IIDDIIG PROCEDURES The proposed bfddfng procedures appear to be the aost controversial provfsfon fn the NOPR1. Most responses fro the conter1 address f11ues r1f1ed fn the lfddfng NOPR. The lidding NOPR, a1 well as 1ectfon1 of the other two NOPRs, propoae bidding procedure gufdelfne1 to dtterlne avoided coat rates. FERC states (lidding NOPR, P. 12): In response to the nuaerou1 coaaent1 on the faple ntation of the avoided cost rule, the Coaaf11fon pro poses to adopt new rules that would ore accurately e1tablfsh utilities' avoided coats. To accoaplfsh thfs, the Commi11fon fa f1sufn1 two proposed rules. Thf1 proposed rule addresses bfd~fng procedures as a means of est1blfshin1 avoided cost rates. The Coaaission is also fssufng a propo11d rule which would reffn~ Its regulations on administratively determined avoided cost In Docket No. RM88. Under the Comalsslons proposal, participants In bid ding would be provided the opportunity to receive capacity payaent1 11 well 11 energy payents a11ocl1ted with the c1p1cfty. Utflftf would still be required to offer to purchase electric energy fro QFs that were unsuccessful bidders for c1pacfty and QFs that did not p1rtfcfpate in the bidding process. Th QF1, however, would be en titled only to avoided energy payments which would be determined 1dafnlstr1tfvely. The bidding procedure presented by FERC was fnftiated because of the perceived probleas with deterafning avoided cost. One such problem that comaenters have noted Is that the avoided cost determination process Is slow and unmanageable (Bidding NOPR, P. 8). Another problem noted in the documents involve the transaction between utilities and QFs. For Instance, many electric utilities complain that avoided coat payments to QFs often exceed the utility's full avoided cost. Many QFs, however, 8 J../7
PAGE 222
complain that the avoided cost payments they receive from utilities are an underpayment compared to a utility's full avoided cost. In addition, QFs do not believe that in all cases t~ey are adequately being given the chance to compete with alternative utility strategies. Ffnally, the 'flrstcome, first served' approach of QF sales to utflfties doesn't always promote sales fro the most efficient QFs to the utilities (Bidding NOPR, P. 8). Df1crepancfe1 among methods u1ed by utilities to determine avoided cost can hinder the development of IPP's becasue investors do not face a consistent set of avoided costs and it therefore fs difficult ot plan. For example, some avoided cost procedures only take into account the utilities' own cost of power production and do not take into account the cost of power fro alternative sources. Also aultfstate utility operators may have proble determining avoided eoat ff determination procedures vary between states (Bidding NOPR, P. 8). FERC has proposed the Implementation of bidding procedures as a method for limiting problems associated with calculating a utility's avoided cost. FERC states (Bidding NOPR, P. 13): The Commission believes that a properly implemented bidding system could effectively address many of the pro blems in implementing the avoided cost rule which were identified in the Commission's conference on PURPA. In particular, the Commission believes that bidding has the potential for eliminating the seemingly endless debates over what alternative sources of supply are truly avoided by the purchasing utility. Avoided c~st need not be an administratively determined number, argued over by experts. Instead, avoided cost could be derived simply and directly from the prices offered by competing suppliers in the bidding process. Because bidding provides a systematic mechanism for identifying potential suppliers, It Increases the chances that the 9 )1X
PAGE 223
purchasing utility's capacity needs will be supplied from the more efficient sources. In light of these advantages, the Commission proposes to adopt regulations under which state regulatory authorities and nonregu lated electric utilities could implement bidding pro cedures as a means of determining avoided cost. Through the new defi~itions of IPPs and the bidding procedures FERC hopes to proaote Increased competitfon in the generation of electricity. There fs controversy surrounding the expected benefits and costs of the proposed rulings and these are outlined in the following sections. We follow the categories as presented in the lidding NOPR document prepared by FERC. BENEFITS OUTLINED IN THE NOPRS Under existing policies, FERC asserts that IPPs development would be hampered and benefits to the utility, consuers and the econoay would not be fully realized. Streamlining the regulations would provide a series of benefits to all parties concerned. These outlined in the IPP NOPR are: New Source of Capacity Least Cost of Supply New Technologies Fuel Mix Reallocation of Risks Reduced Distortion of Investment This section will review these "benefftsN and discuss the expected impacts of the NOPRs as seen by FERC, Commissioner Trabandt and the documents submitted by the interest groups listed in table 1. 10
PAGE 224
NEW SOURCES OF CAPACITY FERC anticipates that IPPs will be a source of new capacity fn the future CIPP NOPR, P. 49) which FERC asserts will be needed because of the perceived uncertainty about the future of electric capacity supply. FERC believes capacity fro IPPs would be another supply option for utility aanagers and that IPP capacity might be available more quickly to et uncertain demand (IPP NOPR, P. 50) with these proposals. On the other hand, Colssloner Trabandt predicts that there will be no increase in overall capacity under the NOPR proposals even ff IPP generation increases (Commissioner Trabandt cites a March 11, 1988 Oak Ridge National Lab Environmental Report; Trabandts Dissent, P. 20 & P. 28> and if there becomes a capacity shortage these proposlas will not lleviate the problem. LEAST COST OF SUPPLY FERC, in the Bidding NOPR states that existing facilities which qualify as IPFs for sales by IPPs have the possibility of being low cost suppliers. The existing facilities are presumed to supply electricity at I lower cost because their capital cost may already be sunk and these units may be fully depreciated (IPP NOPR, P. 51). Therefore the total incremental cost may coapare favorably with a new central station unit. Also, with competition and the lack of a guaranteed market, IPPs would have strong incentives to minimize construction and operating costs of new facilities. Commissioner Trabandt believes that construction and 11
PAGE 225
financfn1 costs could increase under the NOPRs, due to Increased business risk (dissenting comments, P. 39). In evelu1ting least-cost supply, one needs to look at some of the coaponents that ake up the costs. These Include; syste planning; construction leadtfaes; construction and financing costa; and econoaic dfapatch. With regard to syste plannint, the 1r1uaents rest on whether utflltes can incorporate the IPPs Into syste plans. According to APPA, the lapoaitlon of rigid rules will dfainiah the flexlbflfty which least cost planning allows (APPA does not specifically cite a reason for this impact, P. 2) and will impact the way utilities evaluate expansion plans. NERC and SOMPUC (State of Maine PUC) also claim that the expansion planning will be Incomplete because utilities cannot acount for the IPP's in their planning. NERC does say, however, that with proper Information and planning this can be solved. On the other hand CFA&EA (Consumer Federation and Environemntal Action) argue that utilities will be able to adjust to incremental additions of third party power over a considerable period of time because "even if all capacity additions planned for the next ten years were provided by third parties, [these additions] would represent only about 15 percent of total capacity fn 1996." As for the impact on construction lead-times, comments from EEi suggest that there is a potential for longer lead-times if the NOPRs are adopted. EEi believes that the bidding NOPRs would increase uncertainty and therefore would increase the risk of 12
PAGE 226
plant coaplttfon delays (EEi, liddfng Coment, Appendix I, P. 8). Howevtr, 40 Utflfties believe that the use of package or offtheahelf" plants can shorten lead-times. (40 UTIL, P. 68). APPA stated that the new rules may correct the long leadtfme situation which has developed due to "flawed applfcatfon of exi1tin1 technolo1iea (prfarily nuclear). NIEP was the only coaaenter to directly addre11 the fpact of the NOPRs on the construction and ffnancln1 coats. NIEP 1tate1 that IPPs will continue to have a capital ainfafzatfon proble even with the adoptfon of the NOPR1. NIEP suggests that Wall Street financiers and the structure of coapetftive bidding will have a greater fpact on construction and ffnancfng coats than the adoption of the NOPR1 (NIEP, P. 12). The final category addressed fa th fapact on econoafc dispatch. EEi and APPA agree that the lapact on econoaic dispatch of the proposed NOPR1 wfll be ne11tfve. loth expect econoaic dispatch to b fapafred prfaarfly due to technological probleas under the NOPRs (APPA, P. 6 & EEi, lfddfng Comments, Appendix 8, P. 16) and further. APPA does not provide evidence to support this view however, APPA does cite FERC section 205 & 206 and claf this supports the assertion (APPA, P. 6). EEi feels that non-utility generators will be inhibited fro participating in econoafc dispatch because of financial difficulties due to uncertain revenues (EEi, lfdding Comaents, Appendix I, P. 16). However, according to FERC ff the IPPs are the least cost supply, then there should be no proble with econoaic dispatch fro an econoaic standpoint. CFA supports this point fn saying that the empfrfcal record of the performance and 13
PAGE 227
di1patch1bilfty of IPP plants dots not support 11sertion1 bu the utility Industry about their inferior perforance, and therefore, they should bt able to participate fn econoafc dispatch (the State of Maine PUC suggests also 1upports this by saying that Qfs would faprove econoafc dispatch and overall coats because they are l expenafve by deffnitfon). There are 1l10 concerns about increased coats associated wfth the proc111 of econoaic dispatch. NERC a11ert1 that there aay bt additional costs required for control equfpent and line improvements. NERC questions whether the cost of these improveents will be justified, but unfortunately does not supply supporting evidence. There are a nubr of widely divergent views on the impact of these rules on the least-cost of supply to require ore directed study to det1f l the po11fble fp1ct1 of the rules. NEW TECHNOLOGIES The bidding NOPR states that I benefit of the proposed rule changes wfll be I demonstration of innovative technologies. The NOPRs note that traditional co1tofs1rvice regulation may inhibit investment in highrfsk t1chnolo9i1s (IPP NOPR, P. 53 54). There are certain limits inherent in PURPA which Y hinder technological improvement. "If I utility attempts some novel technique for producing electricity, and the effort ends in failure, the company can expect a prudence investigation and 1 possible di1allow1nce of investment costs" CIPP NOPR p. 53). This forces utilites into a somewhat risk averse situation, but 14
PAGE 228
wfth atrealfning regulations, IPPs Y find that the risks of developing new technologies may be tolerable. Cof11foner Trabandt point out that the NOPRs would exclude aoe types of technology fro consideration. This is done by gfvin1 state regulatory a1encfes the abflfty to exclude 1ub1idized technologfes auch as nuclear (IPP NOPR, Appendix, P. 33). He says also that the rules will favor saller fnteraediate load and peaking facflftlea using existing technolo9fe1 because of lower total capital coats. Several comaenter1 address the Issue of technology chofce and new technologies. CIPCA belfeves that adoption of the NOPRs will increase supply options but they do not cite a reason for their predicted Impact (CIPCA, P. 3). In a 1iaflar vein, CFA&EA Indicate that since ller plants using new technologies have becoae considerably more efficient and competitive wfth larger plants (evidence fn academic and policy literature cited in IPP NOPR) there fs greater opportunity for this generation unde the new guidelines. NIEP, however, believes that new renewable and co9eneration projects will be discouraged because JPPs and competitive bfddfng could reduce QF prfces(NIEP, P. a & P. 14). Throughout ft comments, NIEP claims that the government is shifting emphasis away fro energy efficiency toward leastcost supply options only. By this, NIEP implies that aore energy efficient technologies are not the least-cost solutions and that this coapetftfon wilt eliminate from consideration there more energy efficient technologies. 15
PAGE 229
A third perspective is that of APPA. APPA believes that NOPRs are not needed ind no new technology bre1kthrou1hs will occur a1 1 result of the propo1ed rules. In 1ddftfon, APPA state that IPPs ire already being lnt11r1ted Into the current afx of gener1tors and that breakthrough fn technology only wfoll occur becau1e of reffneaents of current chin CAPPA, P. 1). EEi also belfeve1 that the technology choice will be leas than optfal due to regulatory bia1, and the fact that technology choice Y be over1hadowed by the price. According to EEi, ft Y be difficult to 1elect an appropriate coabfnatfon of price and non-price factors fn a bfddin1 concept. It is the consensus that the process of bidding aay produce the least cost plant, but the impacts are unclear. So argue that the bfddint will rule out new, po11fble aore capital fnten1fve technologle1, but others argue that ft will proaote aor efffcfent technologies. IMPACT ON FUEL MIX The NOPR stat that benefit of the proposed rule changes may be the demonstration of I broader range of fossil fuel technologfe1 which have higher efffcfency and that producers who have IPP status may be aore prone to fplement th technologfea than Qfs and fully regulated jurl1dfctfon1l utilities (IPP NOPR, P. 56). Commissioner Tr1b1ndt 1t1tes that the probable result (of the IPP NOPR) would favor natural gas and oil fired generation fn the near term, with possibly so coal ff red p.34). Comafssfontr Tr1b1ndt considers this a proble, while the 16
PAGE 230
Coaaf11fon considers it a benefft: the proposals "may help foster developaent of certain high-efficiency technologies that uae fossil fuels including coabfnedcycle natural 1a1 turbfnes and flufdfzed bed coal bofler1. The two coaaentera who ntion fuel use, faply that ft fa a concern, especially re1ardfn1 th possibility of u1fn1 natural gas CAPPA and NERC). NERC aa1ert1 that the dfaplaceent of 1olfd fuels fn the near ter fa contrary to the Fuel Uae Act. NERC takes the poaftfon that nonutflfty 1ener1tor1 vfll continue to incre11tn9ly depend on natural 1 (they use evidence the proponderence of 1a1 generators), and that heavy reliance on 1 affects longter reliability. It fs clear that all parties expect that natural gas will increase 1s I result of the NOPRs. The question reaina as to whether this fncre11fn1 use of gas fa a benefit or a concern for energy uae In the nation's econoay. REALLOCATION OF RISKS According to FERC, an IPP would assume aost of the risks aa,ocfated with conatructfon and operation because utilities would only have to purchase IPP power on a voluntary basis (IPP NOPR, P. 58) This shift of the rfsks fro the utilities and customers to the IPP investors fs necessary for econoic efficiency "because decisions are then made by the same individuals who bear the risk of their decisions". Custoaers Y continue to bear some of the same risks associated with demand forecaatfng and capacity decfsfons. Nowever,.the 17
PAGE 231
ratepayers are not expected to bear any more risks than they do under current regulations. (IPP NOPR, P. 60). Coaalsafoner Trabandt air that the ahift of rfak to aome extent wfll occur under this process, however he disagrees that the shift fa a benefit. The extent of the rfsk, he claims fa not clear, and aor study fa needed. Ne does state evidence (p. 39) that many of the projects may be unable to obtain financing since lnveatora aay not be willing to take the risks. Again however, the evidence on both 1fde1 fa not overwhelming and as Coloner Trabandt states a systematic and objective analysis of this risk Is clearly warranted DISTORTION OF INVESTMENT According to FERC, the new rules for IPPs would proaote aore r1tlonal fnvestaent decf1lon1. Currently, 10 generation developers bufld PURPA achfne1 which art plantp with a contrived thermal application to avoid public utility regulation (IPP NOPR, P. 61). The new proposals would eliminate these uneconomic investments. COICEIIS OUTLINED II THE IOPRS The NOPR indicates a nuaber of concerns that have been raised about the proposals. These include a number of Issues, and are the ones that are addressed the most fn the dissenting comments. These include: Reliability Power Pooling 18
PAGE 232
RELIABILITY The issue of reliability fa by far the most controversial. It f1 the concern that f1 raised the greatest number of times, FERC and there are ar1uaent1 to support both sides of the Issue. cftes three reasons why relfabflfty will not necessarily be affected by the Integration of IPP1 Into the system. First, purchases fro IPP1 will still be voluntary, and if the utility wtahes to purchase energy or capacity fro the IPP, the utility would be free to ne1otf1t1 ter that ensure reliability. Second, In coaparfson to QF's, the IPPs do not neces11rfly have to support both electricity production and thermal energy production,. For many QF's the primary output fs therMal power, and if those requirements dropped there would be concern that electricity supply l1ht be decreaaed. This would not be 1 concern with the IPPs whose aajor function would be electricity generation. Third, IPPs would have incentive to help utilities t their oblfgationtoserve. The IPPs have a contractural obligation to provide adequate service, and if they fail, they aay not be paid, or the utility Y take the plant over. This, according to FERC, fs a good motivating force for supplying reliable power (IPP NOPR, P. 72). On the other hand, Cofssfoner Trabandt argues that the impact on reliability would be great and negative. The arguments stem fro the technical probles of interconnection and planning. Lack of Information and cooperation Y lead to problems in supply. His concern fs with IPP defaults, ffndfng that 'remedial' 19
PAGE 233
aeaaures outlined are inadequate and place too much emphasis on legal and monetary solutions to problems that are really technical in nature (dissenting opfnfon p. 37). Trabandt also predicts that the NOPRs would result fn Increased reserve r1fn1 because aore backup power would be required (Df11entfn1 opfnfon, P. 65). The coaaenters df1cu11ed thf1 fs1ue fn I number of 1re11 fncludfng: overall 1y1te relfabflity; systea reserve rains; and IPP relfabillty. EEi, 40 Utilities, NEIC, and PSCON, feel that overall syste relfabflity wfll be dffnfshed with the adoption of the NOPR1 (EEi, P. 25, 40 UTIL, P. 85, NERC, P. & PSCOM, P. 6). EEi states numerous reasons for overall system relfabflfty being dfmfnfshed. One of the reasons EEi cites Is that nonutflfty generators aay have fewer back-up or duplicate 1y1tea1 which deer the probability of a tota~ plant failure ff one 1y1tem f1fl1. Another reason EEi gives fs that bfddfng systems cannot or wfll not be designed to properly promote reliability requirements. As result, the IPPs may not be the most reliable plants available and therefore will have a diminishing effect on overall system reliability. The Issue of IPP relfafblfty fs addressed below (EEi, lidding Coment, Appendix a, P. 1). NERC states that ft fs uncertain what nuaber of nonutf lfty generators could be integrated fnto the system without affecting overall system reliability (NERC, P. 13), though NERC believes the non-utility generators can Jeopardize relfability. By this NERC implies that the individual generators will not be 11 20
PAGE 234
reliable as existing 11n1ratfon. NERC al10 notes that non utflfty generators aay not have the sa otfvatfons and obligations 11 utilftf11 and stresses that for th1r1 to bt liait1d impacts on reliability the IPPs aust et the saae requirements for r1li1bflfty that utilities eet (NERC, 'A, P. 7). Public Service Cofssfon ot ~1ryland (PSCOM) concurs that the flexible ~PP r19ul1tfon1 wfll not protect overall Yt relfabflfty becau1e the fnc1ntlv11 do not exist for the non utilities vfth regard to obligatfontostrvt (PSCOM, P. 6). On the other hand, CFA & EA fttl that overall syst reliability will be improved by th adoption of the NOPRs (CFA & EA, P. 8 & P. 12). This conclusion steas from a number of reasons including the use of probability theory which shows that relfabflfty fs Increased a, lltr plants art added to the syst CFA&EA further note that given the unrelfabflfty of large central station nuclear plants ft is fronfc that utflftfes art concerned with the reliability of smaller plants. Also, given take-over and penalty clauses that have been proposed fn contracts, there should be lfttlt concern over reliable supplies. Coments from APPA, EEi, and 40 Utflftfes predict that higher system reserve margins are necessary ff the NOPRs are adopted CAPPA, P. 4, 40 UTIL, P. 9, & EEi, lidding Comments, Appendix I, P. 2, P. 8 & P. 13). APPA believes that there would be a significant nuber of new plants ff costofservice rates art removed CAPPA, P. 4) and therefore to keep existing levels of reliabflrty, utflftfes will need highel" reserve argfns. Thfs however fs based on previous assumptions that IPP generation will 21
PAGE 235
be l reliabil than utility generation. Ell believes higher reserve margins will be needed because of the uncertainty due to lncrea1ed competition (EEi, llddfng NOPR, Appendix I, P. Z, a, and 13). 40 Utllftfts also believes the adoption of the NOPRs will ruult In uncertainty In planning and operatfona (40 UTIL, p. 9). NERC, however, does point out that while saller plants would theoretically require lower syst reserve arglna, that unit coltaent schedules aust be coordinated with the utility to ensure adequate reserve (NERC, 'R, P. 16). NERC does qualify th 1tateaent1 with saying that sa1ller units are generally ore reliable than larger units, and ff there are sets of guidelines for operation and Interconnection of nonutfllty 1ener1tor1 so of th proble can be solved. Many of th arguents depend on whether the conter1 view IPPs as being reliable and whether they can perfor reliably 11 utility operated plants. CIPCA states that IPPs can produce reliable power supplies and this has been shown by existing Independent power producers and QF's (CIPCA, P.5). INTEGRATION WITH POWER POOLS FERC states that IPPs could be Integrated fnto power pools. Purch11e1 of IPP power by utilities would be on a voluntary basis. Thus, FERC states that utflftfes would not have to purchase IPP power unless the IPP met the power pools requireaenta. FERC c1tes 1n Institute of Electrical and Electronics Engineers representative who thinks that IPPa can be 22
PAGE 236
fntegrated Into power pools (IPP NOPR, P. 76). According to Trabandt, the Impact of the NOPRs would be ne11tfve on regional power pooling arrangements due to the bidding and contractual structure set up by th rules. The rtll;bflfty of these arran1nt1 would be reduced (IPP NOPR, Appendix, P. 31). A1 for tran1f11fon r1qufr1aents, Trabandt fl that the Comai11fon needs to address thfa fsaue ore throroughly (IPP NOPR, Appndfx, P. 44). EEi was th only comaenter to addre11 the Impact of the NOPR1 on power pool a1reent1. EEi predicts that power pool agreeaents could be adversely affected by adoption of the NOPR1. EEi feels that power pools agreeents could bt affected ff parties are unwilling to share sensitive fnformatfon. EEi also feels that 1dafnf1tratfve procedures and 11reements will be hindered ff the NOPRs are adopted (EEi, P. 28). NERC blfeve1 that mor contracts would be necessary to facf lftate coordination between utility 1ystem1 because of Increased needs to specify backup requirements, damages, and purchase rights among other factors (NERC, 'A, P. 17). 40 Utflftfts believe that cost assocf1t1d with these contracts would be 1ub1t1ntfal. 40 Utilftfes does not cite reason for the fpact they prtdfcted but they did cite Joskow I Schmalensee as evidence (40 UTIL, P. 74). EEi predicts that actual fnttrsysttm coordination will be affected by adoption of the NOPRs. EEi btlfevts tht r11ulatfons Y ake ft difficult to m1fntafn proper frequency and voltage control (EEi, Bidding NOPR, Appendix a, P. 18). Finally, each of the followfn1 commenters address the fssue 23
PAGE 237
of tr1nsmfssfon access in thefr documents: APPA, CFA & EA, CIPCA, NIEP, and EEi. CIPCA predicts that increased transmission capacity will be needed ff the NOPRs are adopted and does not cite the reason the predict this Impact (CIPCA, P. 28). The other three commenters stress the need for open access to tr1nsaf11fon facilities as a key Issue fn the fapleentatfon of the NOPRs CAPPA, P. 3, CFA & EA, P. 8, NIEP, P. 30, & (EEi, P. 28). APPA believes that electrfcfty afght be oversupplied at lower prices and will put a strain on transalsslon access CAPPA, P. 3 and Appendbc P. 1). CFA & EA find open access to transmission facilities to be essential ff operating efficiency is to be achieved (CFA & EA, P. 8). NIEP believes open access is required In order for competition to take place (NIEP, P. 30). EEi is uncertain about the Impact of the adoption of the NOPRs. EEi suggests that FERC examine the fapact to scale econoales for the transmission facilities needed to serve additional capacity (EEi, P. 28). COIICLUSIOIIS There are a number of issues that have been addressed in these comments that are key to the development of the proposals put forward by FERC. The major one is the rationale for the new rulings, and the disagreements about those reasons. It fs the commissions assertion that there are impending problems fn the electric utility industry, primarily concerned with new sources of supply. Based on recent history, the commission sees problems in future supply due to lack of Investment by utilities. This 24
PAGE 238
lack of Investment Is caused by I number of factors, the primary factor being the risk aversion In the industry. This aay, according to the commission, lead to capacity shortfalls and unreliable supplies of electricity in the late 1990's. On the other hand, the df11entlng opfnfons, led by Coamf11foner Traban~t, feel that there fa no impending crfsfs In electrfclty supply, and under current regulations, utflitfes and prfvate investors, wfll build capacity fn aufffcfent quantftfes to aalntafn the fntegrfty of electrfcfty supply. Both of these viewpoints can be Justified using existing data, and the evidence presented on both sides are not overwhelming. This speclffc issue needs to be addressed fn a comprehensive study which examines the behavior of investment by utilities and private companies, and the relationship between past occurances, economic growth, and investment fn electric power capacity. The second major concern fs the aucess of these proposals in mitigating those perceived problems. Three issues stand out as the most important; ff the rules are truly voluntary" will they have much of an impact?, will the rules provide the least-cost power?, and wfll they Impact relfabfllty of electric supply? The least-cost supply Issue and Its fmplfcatlona fa the centerpofnt of this review. Will the procedure, produce the leastcost supply? Will the competition, force out technologies that are more expensive, but also more environmentally acceptable, or more acceptable In terms of national energy policy? These are not rigorously answered. The most argued concern fs that of reliability. Both sides 25
PAGE 239
present cases on past evidence, ind future 1cen1rfos. Wfth exfstfng evidence ft fs clear that relf1bflfty has not been endangered under exfstfng PURPA rules Cwfth ll penetration of nonutflfty generators). However, what wfll the fpact be ff large nuabers of small JPPs enter grfd7 None of the 1r1uaent1 presented refer to 1nalyse1 that specfffcally address the Issues caused by these propo11l1. The evidence co fro 1tudfes ev1lu1tfng sfaflar f11ues, but not addressing the exact same condftfons. A coaprehen1fve 1tudy ev1luatfn1 the major points fntroduced here, u1fn1 exfstfng Information, and predfctfons on behavioral aspects of investors fs needed to directly address the impacts of the new proposals on independent power production. 26
xml version 1.0 encoding UTF-8
REPORT xmlns http:www.fcla.edudlsmddaitss xmlns:xsi http:www.w3.org2001XMLSchema-instance xsi:schemaLocation http:www.fcla.edudlsmddaitssdaitssReport.xsd
INGEST IEID ENUOFW7LP_EFYNL4 INGEST_TIME 2017-05-24T21:01:58Z PACKAGE AA00055512_00003
AGREEMENT_INFO ACCOUNT UF PROJECT UFDC
FILES
|