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TURNING OUR DARKNESS TO DAWN: THE EFFECT OF THE PREFERENCE CLAUSE ON THE PACIFIC NORTHWEST ELECTRICITY MARKET BY WILLIS SCHUELER A Thesis Submitted to the Division of Social Sciences New College of Florida in partial fulfillment of the req uirements for the degree Bachelor of Arts Under the sponsorship of Richard Coe Sarasota, Florida May, 201 3
ii Table of Contents Chapter 1: Introduction ................................ ................................ ................................ .... 1 Chapter 2: The Development of the Electricity Market in the Pacific Northwest ...... 4 Initial Electrifica tion and the Rise of Electric Holding Companies 1879 1930 ............... 4 The Rise of PUDs and the Founding of the BPA 1930 1950 ................................ .......... 7 Development of Remaining Hydroelectric Resources and the Start of the H ydrothermal Program 1950 1980 ................................ ................................ ................................ ........ 1 2 The Pacific Northwest Power Act an d the West Coast Energy C risis 1980 Present ..... 1 6 Chapter 3: Literature Review ................................ ................................ .......................... 2 4 Literature on and the His tory of the Preference Clause ................................ ................. 2 4 Comparative Efficiency of Public and Investor Owned Utilities ................................ .. 36 Chapter 4:Econometric Model ................................ ................................ ....................... 4 3 Model Specification ................................ ................................ ................................ ...... 4 3 De pendent and Output Variables ................................ ................................ .................. 4 5 Ou tput Variables Specification ................................ ................................ ..................... 4 9 Input an d Cost Shift Variables ................................ ................................ ..................... 50 Chapter 5: Results of the Econometric Model ................................ .............................. 5 4 Description of Utilities in Data Set and Dat a Sources ................................ ................... 5 4 State ment of the Econometric Model ................................ ................................ ............. 5 9 Descri ption of Variables ................................ ................................ ................................ 6 2 Regression Results ................................ ................................ ................................ ......... 6 6 Chapter 6: Conclusion ................................ ................................ ................................ ..... 7 4 Appendix A Additional Data ................................ ................................ .......................... 7 8 Bibliography ................................ ................................ ................................ ..................... 8 5
iii Table of Figures Table 3.1 Percentage of Total Farms Electrified With Central Station Service, Pacific Northwest, by States, and for The Un ited States, Quinquennially 1935 1955 .................. 3 3 Equation 5.1 Regression Equation ................................ ................................ ......... 5 9 and 6 6 Table 5.1 Data Set Descriptive Statistics ................................ ................................ .......... 6 6 Table 5.2 Public Utility Descriptive Statistics ................................ ................................ .. 6 6 Table 5.3 IOU Descriptive Statis tics ................................ ................................ ................. 6 6 Table 5.4 Regression Results ................................ ................................ ............................. 6 7 Ta ble A.1 Correlation Coefficients ................................ ................................ .................... 7 8 T able A.2 Listing of Utilities ................................ ................................ ................. 7 9 and 80 Tabl e A.3 Included Variables Data ................................ ................................ ........ 8 1 and 8 2 Tables A.4 A.10 Mean, Median, Maximum, and Minimum of Total Cost by Independent Variables ................................ ................................ ..................... 8 3 and 84
iv TURNING OUR DARKNESS TO DAWN: THE EFFECT OF THE PREFERENCE CLAUSE ON THE PACIFIC NORTHWEST ELECTRICITY MARKET Willis Schueler New College of Florida 2013 ABSTRACT This study examines the effects of the preference clause in allocating hydroelectric power. Unlike other forms of generation, much of the hydropower resources in the Pacific Northwest are owned by the federal government. Hydroelectric power also has lower costs than alternative forms of generation. The Bonneville Power Administration is federal agency charged with mar keting this power. As electric demand has grown in the region, it has been forced to ration access to hydroelectric power. The BPA uses the federally mandated preference clause to determine the allocation of electricity. According to the preference clause, public utilities are given first preference to BPA marketed power. This thesis examines the far reaching effects that the preference efficiencies of public and private el ectric utility ownership. Dr. Richard Coe Division of Social Sciences
1 Chapter 1 Introduction The s eries of dams in the Columbia River basin that are a part of the Federal Columbia River Power System have a total rated capacity of over 22,000 Megawatts making them, combined, one of the largest hydroelectric complexes in the world. However, the crucial decision of how to market the power generated by the hydroelectric plants of these multipurpose dams was decided three decades earlier in the Town Sites and Power Development Act of 1906 (Norwood 1981) Under this act, surplus ele ctricity generated by federally owned hydroelectric projects is allocated by the preference clause. The preference clause allocates surplus electricity by giving first preference to public utilities and cooperatives as opposed to the Investor Owned Utilities (IOUs) that serve over 70% of the United States electrical customers 1 This clause was first used in the Northwest with the completion of the power house at the Minidoka Dam in 1909 The electricity market in Washi ngton State at the dawn of the Great D epression looked far different than today. The vast majority of the state was served by Investor Owned Utilities controlled by large holding companies. The majority of rural resid ents did not have access to electricity, and they were charged exorbitant hookup costs. Some cities such as Seattle and Tacoma did have municipal electrical utilities but they were prohibited by state law from serving customers outside of city limits. Rura l residents in 1 The phrase public utility is often used to refer to all utilities regardless of ownership status. For this study, public utilities are electric utilities owned by public bodies. For the purposes of this study, this includes member owned cooperative and mutual utilities. Utilities owned by investors are referred to as Investor Owned Utilities (IOUs)
2 unincorporated areas were unable to form an electric utility. In 1930, the Washington State Grange placed Initiative #1 o n the ballot authorizing county wide electric and water utilities called Public Utility Districts (PUDs) It passed narr owly, and it was followed three years later by the start of dam construction on the Columbia River authorized by Franklin D. Roosevelt. Starting with the completion of the Bonneville Dam in 1937, t he F ederal C olumbia R iver P ower S ystem grew into one of the largest hydroelectric complexes in the world over the next four decades. The dams are operated by either the Army Corps of Engineers or the Bureau of Reclamation. The power is marketed and transmitted wholesale to electric utilities for end user distri bution by the Bonneville Power Administration (BPA) Under the Bonneville Project Act, the preference clause was established as the means of allocating this newly developed hydroelectric power. This led to the activation o f PUDs and c ooperatives in the Pacific Northwest, but especially so in Washington. Today O ver 50% of customers in Washington State are served by public utilities, the third highest percentage of any state. It also has the second lowest average retail rate of electricity. This thesis examines the underlying rationale of the preference clause as a method of allocating federall y generated hydroelectric power. It does this by looking at the ownership effects of public and private utilities. Existing liter ature on the subject is mixed as to whethe r public or private electric utilities have lower costs. While it is clear that public utilities in Washington State have lower retail rates than Investor Owned Utilities, this thesis seeks to explain whether lower rates are due to preferential access to
3 B PA marketed hydroelectric power under the preference clause controlling for other differences such as the price of capital and taxes.
4 Chapter 2 The Development of the Electricity Market in the Pacific Northwest Initial Electrification and the Rise of P ower Electric Companies 1879 1930 Electricity development in the Northwest began quite rapidly starting in the used solely for street lights, in competition with g as lighting. In 1879, Thomas Edison and his Menlo Park Laboratory developed small voltage electrical lighting that was suitable for both large scale and small scale applications. The first commercial application of this new form of electrical lighting was the steamship S.S. Columbia, owned by the Oregon Railroad and Navigation Company. After being built in Pennsylvania, it was fitted with electrical lighting, as opposed to the gas lighting in use on other ships, and the S.S. Columbia then sailed to Portland Oregon, to enter service in 1880. Edison later developed the first central electric system with his Pearl Street generating plant electrifying one square mile of Lower Manhattan. This company, Edison Illuminating Company, was the first investor owned ele ctric utility in the world. In short order, electric utilities were developed in the Pacific Northwest. The first was the United States Electric and Power Company in Portland, a predecessor to current Oregon IOU Portland General Electric (Tollefson 1987) Representatives of the Edison General Electric Company established Seattle Electric Lighting Compa ny in 1885, and Edison generating facilities were soon established in several cities in the Pac ific
5 Northwest. In 1885, the falling water of the Spokane Riv er was put to use for the first hydroelectric plant in the Northwest. While investor owned utilities grew rapidly in these initial decades of electrification, municipally owned electric utilities began to emer ge as well. McMinnville, Oregon set up a steam generating plant and began distributing electricity in 1889. By 1895, Seattle and Tacoma (the two la rgest cities in Washington then and two of the three largest today) had set up municipally owned electric systems that developed hydroelectric projects on t he Skagit River, the Nisqually River, and Lake Cushman. Other smaller cities started municipal utilities including Ellensburg, Port Angeles, and Centralia. However, these municipal utilities were not allowed to distribute electricity outside of city limits 2 This led to the formation of several municipal systems in the areas around Tacoma that received power from Tacoma Public Utilities hydroelectric plants. Citizens living in unincorporated areas near Tacoma formed several mutual electric utilities in orde r to gain access to electricity. Mutual electric utilities are a forerunner to a cooperative, in that they are owned by all property owners in their service area. Later that decade t he Bureau of Reclamation built the Minidoka Dam on the Snake River to distribute irrigation water to farmers in Southern Idaho. A power house was finished in 1910. Several municipal and mutual systems were set up in the surrounding area s in order to reap t he benefit s of electricity. As such, this rural area was electrified thirty years before the majority of rural areas in the United States. Two other federal dams with 2 The Washington State Legislature allowed this practice in its 1911 Session, but this was repealed in the subsequent 1912 Session.
6 powerhouses were built to increase the supply of irrigation water in I daho in the decades before the Great D epression. While these dams did have powerhouses, they were primarily built for reclaiming water. D control of the right to develop dams on navigable waterways, no dams with hydroelectric generating facilit ies were built on the much larger Columbia River However, there were proponents of large scale dams on the main stem of the Columbia. An attorney named William Clapp proposed the idea of constructing a dam on the Columbia at Grand Coulee in July 1918. Thi s quickly caught the attention of the publisher of the Wenatchee World newspaper, Rufus Woods. Woods championed the dam in the subsequent decades, arguing that the irrigation water provided by the dam would provide for economic development in largely barre n Central Washington. In the years before the Great Depression, the dam was studied by the Army Corps of Engineers, but no progress was made toward s actual construction. The first three decades of the 20 th century were a time of consolidation and service area expansion for Investor Owned U tilities. From 1900 1920, much of the urban areas in the United States electrified, with many being electrified by small privately held utilities. After 1923, this all changed due to an increased amount of capital availab le for investment. This quickly gave rise to immense amounts of consolidation in the industry. In one year in the 1920s, over 1,000 municipal utilities were purchased by these rapidly growing trusts. They also consolidated control over smaller IOU The s tructure of these holding companies was highly leveraged and complex. Due to their complexity and multistate operations, state Public Utility Commissions could not effectively regulate these holding companies and companies could achieve profits far in exc ess of their
7 regulated rate of return. In the Northwest, five holding companies controlled all Investor Owned Utilities service area in the Pacific Northwest. The largest, Electric Bond & Share, originally created as a subsidiary of General Electric, contr olled electric utilities Pacific Power & Light, Utah Power & Light, Idaho Power, Washington Water Power, Montana Power, Northwestern Electric, and Inland Power and Light 3 This holding company operated in every state in the Northwest along with dozens of others throughout the nation (Bonbright and Means 1969) The Rise of PUDs and the Founding of the BPA 1930 1950 However, the large scale leveraging that led to the creation of these electric trusts led to their downfall. As the Great Depression began, th ese highly leveraged companies began to reverse leverage. This led to mass bankruptcies among the holding companies. The operating practices of the holding companies led to political action in Washington and Oregon. The power trusts refused to serve many r ural areas. If they did, consumers were met with onerous requirements such as high hookup costs and guaranteed minimum bills. Public power systems in operation such as Seattle City Light and Tacoma Public Utilities also provided electricity at lower retail rates than the IOUs controlled by the power trust. This led to an effort by the National Grange of the Order of Patrons of Husbandry, better known as The Grange, to put initiatives on the ballot in Washington and Oregon that would allow for the creation o f public electric utilities that would have the power to condemn the property of investor owned utilities in order to create a public utility. This was important as rural dwellers could form mutual utilities to provide 3 This electric utility is completely unrelated to Inland Power and Light Cooperative operating in Eastern Washington. The cooperative was founded as Inland Empire Rural Electrification, Inc. in 1938 after the dissolution of the investor owned Inland Power & Light.
8 electricity, but mutuals did not have the power to condemn the property of Investor Owned Utilities, while municipal utilities did. This power was important due to electricity even if they did not want to sell. In 1930, State Granges in Oregon and Washington each put an initiative on the fall ballot allowing for the creation of Public Utility Districts in Washington and Peoples Utility Districts in Oregon. B oth initiatives narrowly passed and took effect the foll owing year. In Washington State, the four PUDs were authorized in the 1934 elections with Mason County PUD #1 the first PUD to begin electric service in early 1935 (Public Power Council 2002) In the following decade, 23 further PUDs were created, although not all have offered electric service 4 In Oregon, the growth was slower with four PUDs emerging during the 1940s. However, these new PUDs needed a source of power to begin distribution operations. Mason PUD #1 was able to purchase surplus power from the Tacoma Public Utilities dam on Lake Cushman, but other PUDs were located far away from exi s ting public utility generating plants. In 1931, the Army Corps of Engineers finished their final report on the feasibility of a large dam at Grand Coulee for both hydroelectric power production and irrigation purposes. They concluded that it was feasible, and they also recommended further dam construction at other locations on the river. After taking office in 1933, President Franklin D. Roosevelt authorized the gov ernment to begin constructing the first dams on the main stem of the Columbia River at Bonneville and Grand Coulee. Besides the 4 PUDs were authorized to conduct water utility services in addition from electric utility services from their foundation. Since 2000, they have also been able to offer wholesale broadband telecommunications service s.
9 multipurpose benefits the dams provided in forms of inexpensive hydroelectric power, irrigation water, and the creation of a nav igable waterway for boat transport, the dams also put thousands to work under the auspices of the Depression era Public Works Administration (Ogden 1949) As the dams pressed forward toward completion in 1935, Congress began debating how to allocate the h ydroelectric power from the dam. Legislation dating to 1906 had established a preference for pub lic utilities and cooperatives and was reinforced in the 1920 Federal Water Power Act. Some congressmen advocated for a Columbia Valley Authority that would not only distribute power from the dams, but would also undergo economic development activity similar to the Tennessee Valley Authority. Investor owned utility interests lobbied for a bill that allocated the power solely to IOUs and large industrial c ustomers and there be no federally owned transmission grid. Eventually, a compromise was reached in 1937, and the Bonneville Project Act of 1937 was passed. The preference clause remained intact, an d there would be a federally owned transmission system administere d by the newly created Bonneville Power Administration. However, the Bonneville Power Administration was limited in its scope. It could solely market and transmit power generated by Bureau of Reclamation and Army Corps of Engineers to wholesale customers i n its service territory in Washington, Idaho, Oregon, and Montana west of the continental divide (Norwood 1981) 5 As the power from the Bonneville Dam became available in 1937, the new Bonneville Power Administration quickly set up the framework for regi onal power 5 This was later amended to include any area that is in Washington, Idaho, Oregon or within the Columbia River drainage basin. As such, small areas in California, Nevada, Utah, Wyoming, and Eastern Montana are now part of the BPA service area.
10 distribution under the leadership of J.D. Ross, a former head of Seattle City Light and also a Securities and Exchange Commission commissioner. Ross undertook four initial steps that have affected the operation of the BPA to this day. The first step was the so called postage stamp rate. Ross established the wholesale rate of the BPA to all its customers at .2 cents per kilowatt hour despite lobbying by IOUs and Portland interests for lower rates due to their proximity to the Bonneville Dam. The second was direct service to selected industrial customers. While industrial development was not specifically mentioned in the Bonneville Project Act, Ross believed that the Northwest was b oth underdeveloped industrially and that there would be an eventua l surplus of power available to attract industrial development. These Direct Services Industries were primarily aluminum smelters. The third was helping operationalize existing public utilities that did not distribute power. The BPA provided legal and oper ation al assistance for PUDs in negotiating or condemning the electric plant of existing IOUs. The fourth was the construction of a federal transmission system, which would bring the electricity generated by the far flung dams along the Columbia to utilitie s throughout all of the BPA service area. By creating a federal transmission grid, the BPA did not need to negotiate with IOUs in order to wheel their power over their transmission lines. The planned transmission grid was extensive and served all major pop ulation centers at the time in the service area. Investor Owned Utilities also went through a major transformation during this time period. Congressional investigation of the practices led to a major reform of IOU operations. This was done through the Pub lic Utility Holding Company Act of 1935. Reforms included that an electric utility could only serve a contiguous service area. This
11 forced the large power trusts that operated coast to coast to divest hundreds of electric utilities. Utilities were also for ced to divest themselves from unrelated companies and reduce the complexity of corporate structure found under the power trust. These provisions prevented double cost recovery fr om operating in other states and also selling power at artificially high price s to other units of the company as was common among electric utilities that owned electric streetcar operations prior to the act. After the act was upheld by the courts, the utility trusts divested all of their northwest utilities during the utilities were recapitalized by selling stock to the public (Tollefson 1987) Coulee Dam first started generating electricity in early 1941, and more generators were instal led throughout the decade. The Grand Coulee Dam currently has an installed capacity of 6,809 MW and is the largest power plant in the United States, and the fifth largest dam in the world by installed capacity. At the time of its construction, the Hoover dam was larger, but subsequent upgrades have increased capacity. The large amount of new generating capacity was used to supply electricity intensive war industries such as metal and chemical manufacturing. The availability of large amounts of i nexpensive electricity led also to the location of the Hanford Project near Richland, Washington. Hanford was home to the world first plutonium production reactor in the world for use in nuclear weapons. Public utilities and cooperatives continued to begin electri c distribution functions throughout the decade. By 1950, all 23 public utilities in my data set had begun electric operations. The mission of rural electrification was largely complete as well. By 1950, over 90% of farmers in the Northwest had electricity, well over the national average (Farris 1957) As demand for el ectricity for use in residences
12 and non wartime industries increased, construction of additional dams in the Columbia River Basin began. Development of Remaining Hydroelectric Resources and the Start of the Hydrothermal Program 1950 1980 demand. The BPA began marketing the power of three new dams on the Columbia, and several other smaller dams on other rivers in the Pacific Northwest. However, all of these dams began before the Eisenhower administration was inaugurated in 1953. Under the new Secretary of Interior, Douglas McKay, the Interior department implemented a new partnership policy in which the federal dam woul d license utilities to build dams instead of the federal government. This led to worries among public power advocates that private utility companies would be able to build large hydroelectric projects on the main stem of the Columbia River. In order to cou nter this, Grant County PUD, Douglas County PUD, and Chelan PUD applied for licenses to construct the five Mid Columbia Dams: Wells, Rocky Reach, Rock Island, Wanapum, and Priest Rapids. The se three utilities (better known collectively as the Mid C utiliti es) subsequently received licenses and built the se five dams throughout the next two decades. It should be noted that bonds used to finance the dams were backed by long term power sales agreements with Investor Owned utilities for some of the power generat ed by the dam. Investor Owned Utilities did build some River near Hells Canyon. These three dams prevented a long proposed higher capacity federal dam in Hells Canyon (Tolle fson 1987)
13 The partnership policy led to worries that the smaller public utilities would lose out on future generating sites due to the larger size and lobbying abilities of IOUs. In order to combat this, they formed the Washington Public Power Supply S ystem (WPPSS) as a joint operating agency of seventeen public utilities in Washington State in 1956. Federal dam building began anew near the end of the decade, as more dams on the Columbia began construction including the first of four proposed federal d ams on the Lower Snake River. Electric demand growth steadily rose around 7% annually, leading to the need for these new generating facilities (Pope 2008) The 1960 s saw continuing rapid population and economic growth in the Pacific Northwest. With that, electrical demand continued increasing at similar rates to the hydroelectric plants by the federal government on the main stem of the Columbia and Lower Snake Rivers. The reg ion s public utilities were worried about future energy shortages as the number of possible new dam sites on the Columbia decreased. The first project undertaken was a small dam on Packwood Lake. In 1962, it received approval from Congress to build a nucle ar reactor to generate power using steam from the dual purpose N Reactor on the Hanford Reservation, which was also used to produce weapons grade Plutonium. Under the bill authorizing the dual purpose N Reactor, half of the power was to be sold to IOUs, re gardless of the preference clause, which had been (Pope 2008) The BPA also increased its generating capacity via a new treaty with Canada. This agreement had five major principles. The first was that Canada would build three new dams in Canada for the primary purpose of storing water to reduce seasonal variation
14 (as well as, flooding ) and increase overall power generation. These dams would increase American power generation significantly, and as such, Canada would receive half of the benefits that came from the new dams. As British Columbia already had surplus hydroelectric power generation, its share of power from the dams (kno wn as the Canadian Entitlement) would be marketed and sold to United States Utilities. Ho wever, during the times of high stream flows in the spring and summer, the Pacific Northwest also had an electricity surplus. This two pronged problem was solved with the Pacific DC Intertie. The intertie was a long distance transmission line constructed f rom Northern construction stretching for over 800 miles. This allowed surplus hydroelectric power to be sold in California and other areas of the S outhwest replacin g more expensive thermal power plants. Some of this power was exchanged so that in low water conditions in the winter, power generated in California and the Southwest can flow northward. This arrangement is beneficial as Pacific Northwest electrical deman d is winter peaking due to residential electric heating demand while California is summer peaking due to residential air conditioning demand. One final piece of legislation was necessary to cement the intertie and the Columbia River Treaty with Canada. Was Jackson and Warren Magnuson sponsored the Pacific Northwest Regional Preference Act of 1964. This act codified a regional preference for utilities in the BPA service area for power marketed by the BPA. Power sales to utilitie s outside the service area were recallable with 60 under this law. As such, all sales using the intertie are short term (Norwood 1981)
15 When BPA administrator David S. Black took office in 1966, he warned that federal hydropower capacity woul d be largely developed by 1975. He further warned that continued load growth would necessitate one million kilowatts of new generation capacity each year after 1975. Utility officials from both private and public utilities came Joint Power Planning Council and in 1968, released the hydrothermal program. Under the program, the rem aining federal dam construction would continue wit h dams on the Lower Snake River and Clearwater River, and upgrades would be made to powerhouses at som e dams including Bonneville. In the twenty year period after 1975, 20 new thermal power plants would be built to meet increased electrical demand in the region. These 20 total plants were estimated to cost 15 billion dollars and have a combined capacity of 20 million kilowatts. WPPSS would build and operate the public utility power plants financed by its Washington State member public utilities and other public utilities in the BPA service area. The BPA would participate through net billing. Under net billi ng, pu blic utilities furnish electricity to the BPA, which blends it with federal hydropower, and sells this to its customers. The public utility owners of the thermal plants have their power bills reduced by their share of the thermal power plant costs. T he first groups of project financed by net billing included three nuclear power reactors operated by WPPSS. Importantly, cost overruns on the net billing plants would increase the BPA overall total costs despite the agency not operating the plants (Tollefs on 1987) The early 1970s saw several of the projects started in the 19 60s finished. The last Canadian storage dam was finished in 1973. By then, the increased power generation from the intertie was already flowing south on the completed Pacific DC inter tie. An
16 additional AC intertie started construction in the early 1970s to link Oregon and Northern California. By 1975, the hydro part of the hydrothermal program had been finished with the dedication of the Little Granite Dam on the Lower Snake River. Whi le there were a few smaller potential hydroelectric dam sites available in the Columbia River Basin, there was also increasing anti dam lobbying from environmental, recreational, fisheries, and tribal groups (Needham, 2006) As power demand grew, work bega n on the first six of twenty thermal projects in the hydrothermal plan. Of these, Investor Owned Utilities built coal fired power plants in Wyoming and Washington along with the Trojan Nuclear Plant in Rainier, Oregon. WPPSS concurrently began construction on three nuclear plan ts starting in 1973. By 1975, WPPSS was planning for the construction of two more nuclear plants. These would not be net billed through the BPA as the IRS had ruled that bonds issued under net billing would not be tax exempt. Still W PPSS solicited commitments from o ver a 100 northwest public utilities to purchase shares of the output of these two which gave notice that in seven years, the BPA would not be able to serve all of customers' preference needs (Pope 2008) The Pacific Northwest Power Act and the West Coast Energy Crisis 1980 Present As the electrical demand of public utilities grew, the preference clause began being used more as a rationin g agent in favor of public utilities. This led to a regional political struggle as a far greater percentage of electric customers in Oregon and Idaho are served by IOUs, and thus, Washington was seen as getting far more benefits than its preference clause. Oregon even created (but never activated) the Domestic and Rural Power Authority of Oregon in order to attempt to qualify the whole
17 state as a preference customer. In 1980, a political compromise was reached and signed into law by Presi dent Carter as the Pacific Northwest Power Planning and Conservation Act of 1980. The act had several notable provisions. One authorized the BPA to acquir e generating facilities, but prohibited them from constructing new power resources. It also created a new body called the Northwest Power Planning Council. The council was charged with developing a plan to meet the future projected e nergy shortfalls and creating a plan to develop fish and wildlife mitigation caused by the Federal Columbia River Power Syste m. It also legally authorized conservation as an energy planning resource, recognizing the value of demand side reduction as opposed to earlier focuses on supply side growth via new generating capacity. The most controversial provision is the Residential Exchange program. Under this provision, residential and small farm customers of IOUs in the BPA service area would receive some of the benefits of the federal syst em via BPA payments to the IOUs. IOUs are required by law to refund these payments directly t o their residential and small farm customers on their electricity bills (Public Power Council 2002) Construction on the five WP P began. While all five plants were significantly delayed and over budget, WPPSS board members and other regional public power leaders advocated continued construction on capital costs required to finance construction of the plants coupled with newer ec onometric forecasting techniques that incorporated realistic assumptions such as some degree of price elasticity for electricity (in decades prior, BPA forecasting largely consisted of looking at previous average load growth and projecting that trend forwa rd)
18 led to a crisis within WPPSS. Eventually, under pressure from new BPA administrator Peter Johnson, WPPSS terminated the two non net billed nuclear power plants WNP 4 and WNP 5. This led WPPSS to default on the bonds being used to construct the project, constituting what is still the largest municipal bond default in U.S. history. While this had no effect on BPA wholesale rates, almost all public utilities in the region had power contracts with these incomplete plants with the notable exception of Seatt le City Light (Wilma and Crowley 2010) leading to increases in power retail rates In 1983, the WPPSS board made the decision to mothball 2 of the net billed nuclear plants as well due to cost overruns and lower than exp ected electrical demand. At this p oint, it became clear that the prophesied decade of shortage had become a decade of surplus This sudden change was due to consumers reacting to higher electricity prices by slowing demand growth and the utilization of conservation programs to decrease dem and as well. However, the four never finished WPPSS nuclear plan ts led to increases in electric rates for all consumers, and electrical utilities and their customers are still paying off the bonds that financed the net billed plants today through higher BP A rates. The Columbia Generating Station, the one WPPSS nuclear power p lant completed, began generation in 1984, seven years behind schedule. The rest of the decade saw relative stability due to the surplus generating capacity in the region. Desp ite increa sing BPA funding for s Columbia River salmon species was listed under the Endangered Species Act in 1991. By the year 2002, twelve different Evolutionarily Significant Units (ESU s ) of salmon that spawned in the Columbia R iver system were listed under the Endangered Species Act. There were also ESUs from salmon that spawn in undammed rivers in the Pacific
19 Northwest. This initial listing required the agencies that operate dams on the Columbia River system to consult with the National Marine Fisheries Service in order to make sure the dams' operation did not affect the fish species or their habitat. In 1993, the agency issued its first biological opinion on how dam operation could meet the goals outlined above. This biological opinion was ruled as flawed in court in 1994, and it was sent back to the agency for revision. In the two decades since the first biological opinion, not a single one has been upheld by the federal court system. The BPA and dam operators on the Columbia R iver have done several steps in order to increase salmon returns. These include retaining water in storage dams over the winter to speed fish velocity to the ocean in spring, increased water diversion through spillways, and insuring stream beds are submerg ed. These three steps have reduced the Firm Energy Load Carry Capability of the BPA by around twenty percent. Some environmental activists have advocated breaching some dams on the Columbia in order to restore salmon runs including the four Lower Snake Riv er dams. In recent yea rs, two dams on the Elwha River and one dam on the White Salmon River have been decommissioned partially to restore fish populations. However, these three dams had a combined generating capacity of fewer than 100 megawatts, while the Lower Snake River dams have a combined generating capacity of over 3,000 megawatts (Public Power Council 2002) of 1992 paved the way for FERC orders 888 and 889 later in the decade. Under these orders, owners of generating plants and transmission lines were required to separate these two businesses. Transmission lines owners were mandated to open their lines to unlimited access with published tariff schedules While the BPA h ad allowed wheeling
20 on its lines for several decades, it had complete discretion on whether to do so. New Independent Power Producers first envisioned under the Public Utility Regulatory Policies Act of 1978 were becoming more commonplace. In 1995, power m arketers Services Industries (DSIs) This was the first time that the BPA rates were above the market rate. The BPA quickly moved to cut costs and modify its contracts with both public uti lities and the DSIs in order not to miss an interest payment to the federal treasury. It also terminated its effort to acquire new generating facilities except for small renewable resources. In the meantime, several states began to deregulat e electric distribution as they had generation and transmission. These included Montana, Oregon, Independent Power Producers and the retirement of the Trojan Nuclear Plant in Oregon some utility power planners believed that the shortages feared twenty years ago had finally come to roost as the Pacific Northwest was dependent on wholesal e power from the Southwest especially during a drought year (Bonneville Power Administration 2012) In May 2000, wholesale power prices in California began rising. They continued to rise throughout summer. These wholesale prices spread to the Northwest a nd continued t o shoot upward as a drought took hold of the Northwest, leading to the second lowest river levels in BPA history. This drought continued into winter, leading to ever higher wholesale power rates, over ten times what they had been the previous winter. This was partially due to market manipulation by Enron and other new entities in the new deregulated electricity. Wholesale power rates did not reach early 2000 levels until July
21 2001. This forced the BPA and its member utilities to enact large de mand side reduction efforts in order to av oid blackouts. Overall, the BPA lost over 700 million dollars during the West Coast energy crisis due to the spike in purchased power costs. The reaction to the crisis also led public utilities that had diversified their load to the BPA. In less than a decade, the BPA had gone from fears of huge power outflow to not being able to meet the power needs of all of its preference customers. The deregulation boom of the 1990s had bust ed, and the BPA was now again the cheapest wholesale electricity provider in the region despite a 46% rate hike to recover the costs imposed by the crisis. This also put an end to distribution deregulation in the region. Oregon and Montana both suspended distribution deregulation as did California after the energy crisis. No states in the BPA currently offer retail choice or any form of retail choice in electricity, but the deregulation in generation and transmission remain in place. The middle of the 2 000s was a welcome decade of stability for the BPA after the West Coast energy crisis at the dawn of millennium. As the wholesale market stabilized, the BPA was able to cut rates multiple times in the immediate years after the crisis. Both Washington and O regon created renewable portfolio standards for utilities. Both of the measures controversially exempted non new hydroelectric generation. The Washington Standard calls for 3% renewables by 2012, 9% by 2016 and 1 5% by 2020. Utilities have primarily been us ing new wind capacity to meet their obligations under Initiative 937 (Bonneville Power Administration 2012) resource mix has been challenging in spring months when both hydroelectric and wind power production peaks In recent years, in order to maintain stream flow the BPA has both shut off wind generating capacity and sold power for no cost due to excess
22 generation. In 2005, the BPA agreed to limit the amount of power that it sells at its priority firm (i.e., prefe rence customer) rate to around 7,000 megawatts, the capacity of the total federal system. Prior to then, the preference clause was used as a rationing agent between public and private utilities. However, total system capacity was being used to ration firm power to public utilities as well. With no prospect of increased generating capacity on the horizon, public utilities that need more power would either have to pay higher Tier 2 rates for the BPA to acquire additional power for them, acquire it via the spo t market or increase their own generating capacity. This tiered system of rates was put in place for new power contracts signed in 2011 lasting until 2028. The BPA celebrated its seventy fifth year anniversary in 2012. Its impact on the regions electric al market has been substantial. BPA preference power led to the formation of dozens of e lectric utilities in Washington, as well as in other states in the Pacific Northwest by providing inexpensive federal hydroelectric preference at cost. T he Pacific N ort hwest electrified fa ster than the nation as a whole. Today, Washington State has the second lowest average retail rate for electricity of any state in the nation. These multipurpose dams have also allowed river transportation on the previously unnavigable Columbia and Lower Snake rivers, a nd irrigation water that irrigated the drylands of Eastern Washington, Eas tern Oregon, and Idaho, which are now some most productive agricultural regions. In a world harmed by the carbon dioxide emissions o f thermal power generation, Washington State is in en viable position of having over 6 0% of its electricity come from emission free hydroelectric power. However, with all the benefits have come costs as well. Salmon runs are a fraction of their previous st rength. The dam reservoirs have flooded previous ly occupied land, relocating towns
23 and tribes and destroying historic sites. The BPA and the Federal Columbia River Power System have had a substantial impact on not just the electricity market, but the regi on as a whole.
24 Chapter 3 Literature Review Literature on and the History of the Preference Clause Some form of public preference for federally generated electricity dates back legislatively to the Town Sites and Power Development Act of 1906. Ho wever, L ee C. White and Stanley Freeman writing for the American Public Power Association, date it all the way back to the Northwest Ordinance of 1787 (White and Freeman 1981) At the time of the Northwest Ordinance, some European states allowed nobles to own sect ions of rivers and charge tolls for river passage. The Northwest Ordinance stated that the Mississippi and St. Lawrence River systems were to be forever free of taxes, imposts, and duties, establishing waterways as public land with the federal government h aving the ability to regulate diversion of a river such as for dam building. Other accounts of the history of the preference clause differ with respect to the origin of the preference clause. Economist Martin Farris contends that while this clearly estab lished inland waterways as public land, it is not a direct antecedent (Farris 1957) Both authors along with a 2001 GAO report do agree that the 1877 Desert Lands Act set an important precedent for th e preference clause (Government Accountability Office 20 01) According to this act some public agencies have first preference to surplus reclamation water from federal reclamation projects. Three decades later, dams primarily meant for water reclamation could also generate hydroelectric power. As early as 1903 Theodore Roosevelt vetoed the private construction of a dam and power house at Muscle
25 Shoals, Alabama. In 1906, he signed The Town Sites and Power Development A ct giving preference for this surplus hydroelectric power to municipal governments. The legis lative histories on this act are silent on who actually wrote the preference clause, but there are unconfirmed reports that either Gifford Pinchot or William Randolph Hearst conceptualized the idea. This act soon had impact in the Pacific Northwest. In 19 09, a power house was added to the Minidoka Dam on the Snake River in Idaho. This allowed for the nearby city of Burley, Idaho to create a municipal electric utility to purchase power from the dam (Tollefson 1987) T he next major hydropower legislation ma ndating preference was The Raker Act of 1913. This controversial act allowed the City of San Francisco to reclaim municipal drinking water by constructing a dam in Yosemite National Park's Hetch Hetchy Valley. The act did mandate that the dam used to recla im water for San Francisco would also contain a powerhouse that would generate electricity to be sold directly by the municipal government. In violation of this act, the power from this dam continues to be sold to Pacific Gas and Electric, an Investor Owne d Utility. T he Federa l Power Act of 1920 was an important expansion of preference. While the Town Sites and Power Development Act gave preference to municipalities, the new act gave preference t o municipal bodies. The phrase m unicipal bodies was meant to include all forms of government at and below the state level such as counties, and special purpose districts like irrigation districts Similar clauses were included in the congressional authorizations for the Salt River Project in Arizona and the Hoover Dam (Farris 1957)
26 The other major U.S. Government Power Marketer is the Tennessee Valley Authority (TVA). Before the TVA's preference clause is discussed, the important differences between the BPA and the TVA need to be analyzed. The TVA and the TVA act w ere an attempt to economically develop the poverty ravaged Tennessee Valley. The main aim of the TVA was to electrify a region where the majority of homes lacked electricity. Other economic development plans had little to do with electricity, such as incre asing fertilizer use to increase crop yields. One key aspect that the Bonneville Project Act lacked was a secondary power preference to large indus trial users in order to increase economic development The other major structural difference is that the TVA is a generation and transmission utility unlike the BPA. T he BPA only acts as a transmission and power marketing agency. Generation facilities are run by the Bureau of Reclamation, the Army Corps of Engineers, or in the case of the Columbia Generating Stat ion Nuclear Power Plant, Energy Northwest. The TVA act was challenged in court and was upheld by the Supreme Court in 1936 with one part of the opinion allowing the TVA to dispose of federal power in any reasonable manner. The Bonneville Project Act of 193 7 is what beg at the Bonneville Power Administration. However, section 4 is directly relevant as it contains the preference clause for the power Bonneville markets. In order to insure that the facilities for the generation of electric energy at the Bonnevi lle project shall be operated for the benefit of the general public, and particularly of domestic and rural consumers, the administrator shall at all times, in disposing of electric energy generated at said project, give preference and priority to public b odies and cooperatives. (Bonneville Project Act 1937 ) Scholars on the preference clause note several significant changes in this law's clause. One is the inclusion of cooperatives, first done in the TVA act. The second is the
27 additional emphasis on pref erence in the last sentence. The word priority is used here, but not in any other federal acts dealing with the preference clause. Even subsequent acts such as the Flood Control Act of 1944 do not include the word priority when dealing with surplu s federal hydroelectric power (Norwood 1981). There are four subsections contained in Section 4 of the Bonneville Project Act that helped ensure that the intent of the preference clause was met, and not disregarded as it is in the Raker Act. The first preference command stated that in the case of competing applicants, public bodies and cooperatives should receive preference. This ironclad clause helped ensure preference customers continued to be served when load growth began to outpace supply growth in the 1970s, resulting in the decline of power sales to non preference customers such as Investor Owned Utili ties. The second command allowed cooperatives and public utilities sufficient time in order to secure financing to enter the electric utility industry. The thir d allowed public utilities sufficient time to begin electric service The fourth was a pullback clause that allowed the BPA administrator to cancel power sales to non preference customers in order to serve preference customers with a five year cancellation period. While preferenc e clauses were included in subsequent legislation such as the Reclamation Project Act of 1939, the Rivers and Harbor Act of 1945 and the Niagara Redevelopment Act of 1957, they were mostly concerned with extending preference clau ses similar to the BPA's and TVA's at additional federal power projects. The policy of preference was enshrined in law as the way to distribute federally generated power. As the Federal Columbia River Power System was built out the BPA continued to give p reference in marketing the new power to public bodies and cooperatives.
28 The detail and clarity in the preference provisions of the Bonneville Project Act hostile to pub lic power interests. Farris recounts the many ways in which Eisenhower's secretary of Interior, Douglas M cKay, tried to roll back rights for preference customers, such as by the partnership policy that froze federal dam construction and encouraged individu al utilities to construct power generating dams. This naturally favored larger private utilities with greater construction capabilities and capital. Worries about private power dams on the main stem of Columbia dam led Grant, Douglas, and Chelan County PU Ds to obtain permits to construct five dams whose power would not be marketed by the BPA. It also led to the formation of the Washington Public Power Supply System (WPPSS) as a consortium of public power agencies, to better compete with IOUs for dam licens es McKay believed that the federal government should only build transmission lines from dam sites if alternatives such as private transmission lines were not available. This led to situations such as the Fort Peck Dam, where after completion there was onl y one potential customer, an Investor Owned Utility, who received the power at dump (surplus) power rates (Farris 1957) Northwest prevented this from occurring in the BPA service area. The Clark Hill pro ject is menti oned by nearly all authors on the preference clause as a case where the Eisenhower administration acted directly contrary to the preference clause. In 1954, the federal government finished constructing the Clark Hill Dam (n ow Strom Thurmond Da m) near the Georgia/South Carolina border with the power ultimately flowing to Georgia. Local preference utilities in this case cooperative utilities asked the government to construct transmission lines from the dam to serve their electric
29 cooperatives. Since the Southeastern Power Administration under the aegis of Mckay's Interior Department refused to build the requested transmission lines, the electric cooperatives applied to the Rural Electrification Administration for a loan to build transmission lin es. This was also refused due to lobbying by the incumbent Investor Owned Utility in the area, Georgia Power. By blocking cooperative access to the power from the dam, the Interior Department was attempting to have power from the dam sold only to Georgia P ower The cooperatives would then have to purchase electricity from Georgia Power system wholesale rates, which were much higher than the Southeastern Power Administration wholesale rates Eventually, the Interior Department asked the Justice Department f or a legal opinion on the case. The Justice Department ruled that the Interior Department clearly acted in violation of the law under these actions. Thereafter the Interior Department tried to suppress knowledge for this decision for two years (White and F reeman 1985) This example shows that administration is a key factor of the impact of a law. There have been no similar cases in the Pacific Northwest due to the administrative independence of the BPA (unlike the Southeastern Power Administration, which is un der the Department of Interior) and the explicit authoriza tion for the BPA to construct a transmission system. Subsequent presidential administrations were more favorable towards public power and offered littl e administrative interference to the fede ral power marketing agencies including the BPA. The passage of the Pacific Northwest Power Preference Act of 1964 established regional preference for Pacific Northwest sales over any sales outside the region. It also allow ed ere is no current market in the region or that cannot be conserved for use in the region. ( Pacific Northwes t Consumer
30 Power Preference Act 1964) other southwestern states would not have equal acces s to BPA power. This did prove beneficial in that the BPA could generate revenue or swap power when it had excess capacity. Issues surround ing preference laid mostly dormant until the middle 1970s. One year after the final dam of the Federal Columbia Riv er Power System was completed in 1975, the BPA issued a long threatened notice of insufficiency to preference customers. It stated that in seven years (1983), the BPA forecasted that it would not have enough firm ds. If this were to occur, not only would power have to be rationed by preference customers, but furthermore, investor owned utilities would not be able to receive any benefits of the preference clause. Since public utilities served a much higher percentag e of customers in Washington than neighboring Oregon and Idaho, this rationing, threatened to set off a regional war over the benefits of the BPA ( Public Power Chronicle 2002 ) This came at a time of increasing nationwide attempts to circumvent preferenc e ( White and Freeman 1985 ) Non utility agencies such as New York City's Metropolitan Transit Agency attempted to gain access to preference power. Fearing a regional power shortage, Oregon even attempted to create the Domestic and Rural Power Authority of Oregon to qualify the entire state for preference power. A legislative compromise was reached with the N orthwest Power Act of 1980. As discussed previously, the act contained the residential exchange program, which allowed Investor Owned Utilities to reap some of the benefits of the preference clause
31 In the three decades since the Northwest Power Act, preference in the northwest and nationwide has l argely remained static BPA generation capacity peaked in the 1980s, and has been slightly reduced since due endangered salmon species. There have been no serious attempts to study alternatives to preference since some attempts by the Reagan administ ration ( Freeman and White 1985 ) The Alaska Power Marketing Administration was sold in 1995 due to small size and the political influence of Alaska's congressional delegation (Kufahl 1996) Preference today is ensconced on the federal register as the sole way to distribute federally generated power. Public power advocates White and Freeman identify six reasons in su pport of the preference clause (White and Freeman 1985) The first is that electricity generated from federal hydroelectric facilities should benefit public entities rather than for profit private entities. The second and third rea sons are intricately rela ted. They say that hydroelectric facilities should be distrib uted to promote public purposes such as preventing abuses of monopoly power The existence of federal hydropower has supplied an important generating source for all the public utilities in the Pa cific Northwest. Without it, many public utilities would have to source their power from private entities, and they would have trouble surviving. The other is that public utility rates are on average lower than private utilities. As such, This allows publi c utility rates to be used as a yardstick for state utility commissions regulating investor owned utilities rates. Going along with the last reason, many public utilities and cooperatives are small in size, so would have trouble either building their own g enerating facilities or sourcing power from the wholesale market especially before deregulation of wholesale power markets in the 1990s.
32 Public utilities are governed either by an appointed or elected board for a defined geographic area allowing for si gnificant local control. In contrast, investor owned utilities are either privately held or governed by a board of directors appointe d by shareholders. Finally, the preference clause allows the federal government to recoup the costs of building hydroelectr ic facilities. When the federal government opened the Canyon Ferry Dam on the Missouri River in Eastern Montana in 1954, the only company with transmission lines to receive the power wa s Montana Power Company (Farris 1957). Due to this, the company receiv ed power at dump power rates. If they were public bodies able to receive this power, the situation might well have been different. White and Freeman also run through four common criticisms of the preference clause. Public utilities receive an unfair adva ntage because federal power distributed under the preference clause is distributed below cost. An interlinked criticism is that federally generated power is cheaper than privately generated power, so it is unfair that public utilities get the first right t o receive this power. An additional criticism he brings up is that certain regions benefit disproportionately from the preference clause and hence, it is inequitable because not all the population has equal access to federally generated electricity. The l ast criticism he mentions is that private utilities are already regulated, so there is no need to give preference to public bodies. In 1957, Farris analyzed the intended and unintended effects of the preference clause in the BPA service area. One of the intended effects was electrification. The BPA service area electrified faster than the U nited States as a whole. By 1955 the region was almost entirely electrified and electrification proceeded faster than the nation as a whole.
33 Farris demonstrates this w ith the table below, which shows that in 1940, 63.5% of farms in the region had electric service compared to 30.4% nationally. Table 3.1 Percentage of Total Farms Electrified With Central Station Service, Pacific Northwest, by States, and for The United S tates, Quinquennially 1935 1955 Area 1935 1940 1950 1955 Washington 47.3 71.4 91.9 98.3 Oregon 27.5 58.8 89.3 97.2 Idaho 29.8 58.3 91.6 96.9 Western Montana N/A 47.5 84.4 94.6 Region Average 36.7* 63.5 90.6 97.5 United States Average 10.9 30.4 77.2 9 3.4 *=estimated Source : Farris 1957, 148 Low prices for electricity also stimulated demand, and, as a consequence, Pacific Northwest consumers used three times the amount of electricity as the national average. Rates were also significantly cheaper than t he nationwide average for both public and private utilities. Farris believes that the lower rates stimulated increased electrical demand in the region. He then lists the unintended effects of the preference clause. The first was the extensive availabilit y of power to private utilities. Even then, much of this was non firm or dump power. By 1973, firm power sales contracts to IOUs were phased out. The other is the availability to Direct Service Industries (mostly aluminum smelters) and federal government i nstallations such as the Hanford Nuclear Reserve. As noted above, the Bonneville Project Act is silent on industrial development unlike the TVA act. However,
34 the availability of large amount of power from Grand Cou lee and Bonneville Dam led to the establis hment of several large industrial firms served directly by the BPA (Farris 1957). 15 DSI customers played an important role in balancing the BPA's load by agreeing to curtail power usage when other demand was high and vice vers a. This allowed more efficient operations of the FCRPS dams. After, the West C oast electricity crisis of 2000 2001, service was severely curtailed to 5 DSI and the amount of power available to them was curtailed to 577 megawatts annually (Bonneville Power Administration 2012) Academic journals in economics have published little on the preference in recent decades. While there are many articles comparing public and private producers in the electricity generation, and electricity distribution markets that h ave implications for preference given its underlying rationale, few directly focus on preference. One of the few articles Economics of Preference Power (Lesser 1989) It is of limited direct applicability to thi s thesis as its strongest focus is on inter regional preference rather than preference among utilities articles deals with the legal and political history of the prefere nce clause discussed earlier. It is important to note here the existence of the BPA intertie transmission line in between the Northwest and California previously discussed in Chapter 2. Lesser then introduces a model of trade to model power sales from the BPA to customers throughout the West Coast. By allowing unrestricted trade, Lesser hypothesizes that retail prices would fall in California and rise in Washington until the aggregate marginal cost of electricity su pply equaled aggregate demand (t here a re costs
35 to long distance transmission). Under this scenario, societal welfare would increase, but Northwest electricity consumers and California electricity generators would face welfare losses. Subsequently, Lesser adjusts the model by asserting that ret ail prices in the Northwest cannot rise due to trade. Under this revised model, society as a whole would see welfare gains, but they are reduced due to the trade restriction. Lesser further revises the model to incorporate average cost pricing. He argues t hat the electricity distribution market is a regulated monopoly governed by average cost pricing. Under average cost pricing, trade can lead to inefficient welfare outcomes for society. In his conclusion, Lesser emphasizes this point, saying a repeal of pr eference under the electric utility market structure could lead to efficiency losses, and any repeal he argues should be scrutinized for efficiency effects and a raft of other issues. While there is little academic literature on preference, trade associat ions such as the American Public Power Association and the Edison Electric Institute (the trade association for Investor Owned Utilities) have released several reports looking at the effects of preference, with many released during the restructuring of the United States electricity market in th deregulation after the West Coast energy crisis led to a dramatic drop in this sort of studies. Many of these studies are also not available online or in libraries. However, an ap pendix to an Energy Information Administration report summarizes many of these studies (Energy Information Administration 2000) Many of these focus on the tax advantages given to both types of utilities. One example is the American Public Power Associatio n 1998 study Public Power's Lower Electric Rates to Customers Are Not Explained by the Use of Tax Exempt Financing and Preferential Access to Federal Hydro Power. This study
36 estimates that only 19.6% of the gap between public and IOU costs can be explain ed by the two factors listed in the title. A study prepared for the Edison Electric Institute, also in 1998, estimated that public power utilities receive a total subsidy of over six billion dollars annually. Comparative Efficiency of Public Utilities and Investor Owned Utilities There have been both public and private electrical utilities in the United States since the 1880s. By 1902, there were 3,620 electric utilities with slightly over 20% having municipal ownership (Hausman and Neufeld 1994) Munici pal utilities tended to be smaller with only 9% of generating capacity. In many areas such as Seattle, there were competing utilities with separate infrastructure The practices of some utilities contributed to the rise of state regulation of utility price s using rate of return starting in 1907 in New York and Wisconsin and spreading across the nation over the next two decades. As electrification spread rapidly across the United States in the 1920s, an increasing number of utilities both municipal and priva te formed in the beginning of the decade. This gave away to increasing consolidation as utility holding companies began acquiring both public and private firms. By 1932, eight holding companies generated over 70% of the electricity in the United States. The rise of utility holding companies in the 1920s led to legislative action in the 1930s. The Public Utility Holding Company and the Federal Power Act of 1935 introduced substantial federal regulatory oversight of private, interstate electric utility comp anies. The Rural Electrification Act of 1936 provided loans to establish electric cooperatives in rural areas under Rural Electrification Administration. This gave birth to a new type of electric utility, a cooperative, and helped extend electricity to rur al regions
37 that utilities had neglected to serve prior. The 1930s also saw the enactment of the TVA Act and the Bonneville Project Act discussed above. The intervening seven decades have seen a largely stable electrical market. The number of public utili ties has held steady while the number of private utilities has decreased significantly. This is due to a steady pace of mergers as economies of scale and further factors promoted large, vertically integrated (generation, transmission, distribution) electri c utilities. The enactment of the Public Utility Regulatory Policies Act of 1978 led to the introduction of non utility generating companies 6 which in turn led to the beginnings of a wholesale market. Similar initiatives were introduced to encourage wheel ing 7 mainly targeting large industrial customers. The Energy Policy Act of 1992 expanded FERC authority, allowing it to order integrated utilities to allow wheeling of a non utility generator over their transmiss ion lines. FERC Order 888 in 1996 went even farther mandating that all companies owning long distance transmission lines publish a tariff schedule and allow nondiscriminatory access. This order also made it possible for companies to 'unbundle' their services in the case of retail deregulation. Ret ail deregulation did occur to some degree in 24 states. Under retail deregulation, customers pay separate charges for transmission and retail distribution, allowing companies to compete on price in the retail distribution market. In the BPA service area, b oth Oregon and Montana enacted deregulation bills (Bonneville Power Administration 2012) but efforts were stopped after the west coast electricity crisis of 2000 01. Critically, retail 6 Also Kn own as Independent Power Producers 7 Wheeling is the act of moving electricity along transmission lines not owned by the generating utility
38 deregulation laws only effect IOU customers, and not customers of coop eratives or public utilities. E conomic studies comparing private and public utilities are almost as old as electric utilities themselves (Hausman and Newfeld 1994) In fact, one of the first actions of the newly formed American Economic Association was t o form a committee to study the effects of municipal versus private ownership in the electric utility sector. Based on qualitative analysis of a mail in survey to 57 cities, it concluded that municipal ownership was optimal for a city. Researchers quickly realized that utilities should be compared by something other than price, as price can be affected by competition, subsidies and a plethora of other factors. Researchers then moved into the field of cost comparisons using controls such as size and adding in imputed interest and depreciation. Other studies examined individual cities that had both public utilities and IOUs. Price and costs comparisons continued to be used well into the future. Farris relies heavily on data from the Federal Power Commission comparing electric bills in similarly sized cities in Ohio and Washingto n (Farris 1957) Due to the limitations of price and cost comparisons, researchers began to try to study productive efficiency. This was di fficult due to the lack of data and lack of modern quantitative methods. After some studies in the 1930s, academic economic research on electric utilities was largely dormant until 1970. This coincided with the development of the property rights theory of the firm. According to this theory, manage rs of a private firm are restrained from abusing their position by the opportunity to divest themselves of an ownership stake in a firm (Alchian and Demsetz 1972) For a manager of a publicly traded IOU, this could be as simple as selling a stock. Stock se ll offs in turn increase
39 pressure on current management to have a good financial performance, or the company might be ripe for a takeover by a more profit maximizing company. Public ownership, however, is marked by little change or divestiture of ownership The owners of the public utility (all ratepayers) could either change their residence or mount some sort of public campaign to lobby the utility to change its practice. Given the small ownership stake that each individual ratepayer has, both options are unrealistic. The lack of restraint on management will lead to favoritism by the public utility either on the income or outcome side. For example on the income side, workers could receive excessive wages; on the outcome side, favored groups may receive belo w market rates. This could lead to revenue shortfalls that would need to be recovered from the municipality. The emergence of the property rights theory of the firm advances in quantitativ e methods, and a renewed interest in comparisons between public an d private firms led to a large number of studies over the following decades. In a comparative study, Peltzman found that on average public utilities have lower prices than private utilities (Peltzman 1972) Peltzman interprets this price differential as public utilities' method of delivering political benefits to customers. He then expands this hypothesis. He argues that public utilities will set rates to benefit the largest number of ratepayers (synonymous with voters) and as such, rates for different u ser classes should be similar. It should be noted that Peltzman did no statistical work beyond simply comparing the prices between public and private utilities. also approaches the comparison be tween public and private utilities from a property rights theory of the firm standpoint (De Alessi 1974) Like Peltzman, he also approaches the comparison between
40 public and private utilities from a property rights theory of the firm standpoint. Likewise, he also found that on average public utilities had lower rates than private utilities. However, he does extend his conclusions beyond Peltzman's. Using a simple price regression from empirical data, he shows that user groups with less user s i.e. industria l ratepayers face lower rates relative to residential rates as predicted by Peltzman. Empirical evidence is also used to support the Averch Johnson overcapitalization hypothesis due to investor owned utilities facing rate of return regulation. The Averch Johnson effect is that when a regulated company's rate of return exceeds its cost of capital, firms are incentivized to increase investment in capital goods as this will lead to increased profits. This behavior is not consistent with cost minimization (Ave rch and Johnson 1962). While Peltzman was the first researcher to use the property rights theory of the firm to analyze the ownership effects for U.S. Electric utilities, several other researchers analyzed the ownership effect for public and private util ities in the three decades between 1970 and 2000. The First was Moore (Moore 1970). He used a demand and cost estimation model to see if electric utilities charge profit maximizing prices. He found that public firms charge 10 22% less than the profit maxim izing price. Next was Meyer (Meyer 1975). He used a cost function to compare costs of public and private utilities. He found that public firms had significantly lower costs overall. Yunker also examined firm's cost functions. Using regressions and price mo deling, he found that while all firms had similar costs, that public firms charge lower rates (Yunker 1975).
41 Other studies looked at ownership effects throughout the 1980s. Many of these used translog cost functions Atkinson and Halverson found that pu blic and private firms are equally cost inefficient at 2.4% away from optimal cost efficiency (Atkinson and Halvorsen 1986). Pescatrice also performed a translog cost function study looking at ownership effects. However, they found starkly different resul ts. They found that public firms were more cost efficient than private firms by 24 33% (Pescatrice 1980) Hayashi, Sevier, and Trapani did a historical study using translog cost functions dating back to the 1960s. They found that while public firms were mo re efficient in the 1960s, in the 1970s investor owned utilities were more efficient (Hayashi et al. 1985) Hollas and Stansel also used a translog function, but used a profit function instead of a cost function. They found that private utility firms were the most efficient type of electric utility followed by cooperatives, and the least efficient they found, were public utilities (Hollas and Stansel 1988) Fare, Grosskopf, and Logan also studied this issue in the 1980s, but using a linear programming tech nique. They found that public firms were slightly more efficient than private firms. Academic economists continued to study this inconclusive issue into the 19 90s. Two studies used the translog cost function technique. A 1994 study by Hollas, Stansell, a nd Claggett, found that IOUs and public utilities have equal costs, but public firm' price was lower to residential customers (Hollas et al. 1994) A different study focusing solely on utilities using thermal generation was conducted by Koh, Berg, and Kenn y found that among small firms, public utilities have lower costs. However among large firms, IOUs have lower costs (Koh et al. 1996)
42 In 199 6, John E. Kwoka published a book researching the differences in efficiencies between public and private utilitie s (Kwoka 1996) Kwoka used quadratic cost models rather than the translog or linear programming models as had been used by earlier studies. He found that public utilities have lower costs than IOUs by an average of 5.5%. He also found that IOUs are more e fficient in generation while public utilities are more efficient in distribution. Kwoka covered similar ground nine years later in a journal Electric Utilities. (Kwoka 2005 ) study. IOUs are more efficient in generation while public utilities are more efficient in distribution. He add s that the latter is a function of size, and that utilities that distribute over 16 mil lion megawatts (no Washington State public utilities distribute more than 10 million megawatts) did not have any comparative advantage, but only 2 public utilities fell in this range. Kwoka attributes this advantage in efficiency in distribution due to the user oriented tasks where quality and reliability are otherwise more difficult to sustain. (Kwoka 2005, 635) Academic literature on comparative efficiency between private and public electric utilities is inconclusive. There are multip le studies showing that IOUs are more efficient, yet there are also studies showing that public util ities are more efficient. T here are furthermore, other studies showing little difference between the two. The comparative efficiency of public and private utilities is still an unresolved issue in academic literature. There has also been little recent academic study on the preference clause. This study is an attempt to study both topics in the region of the Pacific Northwest.
43 Chapter 4 Econometric Model Mo del Specification In order to compare Investor O wned Utilities and public utilities performance under the preference clause, a cost function will be employed. The use of a cost function is standard for this industry as for both types of utilities: rates are based on cost of service. They do differ in that investor owned utilities also include a rate of return for investors of the utilities stocks and bonds (8.25% in Washington State for 2009 as mandated by the Washington State Utilities and Transportation Commission). The latter is one reason why costs are used to model differences between electric utilities rather than revenue. In order for this cost function to be a useful and practical comparison point for investor owned and public utilities, it must be properly specified. The first condition is that there must be monotonicity in total outputs. In short, for a given cost function, an increase in an output must lead to a simultaneous increase in total cost (or in the case of a decrease in output, a decr ease in total cost). This can be shown by a positive non zero marginal cost. A second condition is that it should be linearly homogenous in input prices. Under this, if the cost of inputs doubles the total cost should double as well. A further condition is non decreasing input prices. This condition implies that an increase in the price of any one input does not result in a decrease to total costs. A fourth condition is that there
44 should be concavity in input prices. In a cost function with concave input prices, this means costs increase less than proportionally due to a utility (or any firm's) ability to substitute among its inputs. These four conditions come from the standard economic theory of cost. Further specifications are needed to make a cost fun ction useful for comparing electric utilities. For a multi product cost function such as the one employed in this chapter, the function needs to be able to produce realistic results if some variables have zero values. Most utilities in Washington State pu rchase some of their electricity from the BPA. Two of the three Investor Owned Utilities in the state purchase zero percent of their electricity from the BPA, and the cost function needs to account for this. Another specification relates to the form of the cost function. A cost function should be able to allow for cost properties (or the lack thereof) to emerge from the model and not be specified a priori. This includes properties such as cost function subadditivity, horizontal and vertical integration, economies of scale, and economies of scope. Lastly, parsimony should always be considered when employing econometric modeling techniques (Greer 2011) Current literature on electric utility cost modeling has focused on two forms of cost modeling: transl og and the quadratic. Some of the very first electric utility cost models employed Cobb Douglas functions, but these have fallen out of favor in the field. The translog 8 cost function employs a second order Taylor series approximation using natural logarit hms to approximate an average cost function. One of its advantages is that 8 Translog is an abbreviation for Transcendental Logarithmic
45 is does not impose a priori restrictions on the model such as the above mentioned economies or diseconomies of scale. It also allows inputs to have varying elasticities. However, translog functions have several drawbacks in being used to study the electric utility market. This is due to the model taking the logarithm of all the variables. Since the logarithm of zero is undefined, this model cannot deal satisfactorily with continuo us variables with a value of zero (such as the generation output of utility with no generation plants, which several are include d in the model). Furthermore, this means it cannot estimate an equation with dummy or fixed effect variables (Kwoka 1996) The q uadratic cost model avoids these weaknesses, although it does have some drawbacks. There are no logarithmic terms in the quadratic cost model, so this model is able to estimate regressions using continuous variables with a variable zero and dummy variables However, unlike translog models, it is not linearly homogenous with respect to many researchers prefer the quadratic cost model not only for i ts abi lity to handle zero terms but also for other advantages such as its ability to allow for the emergence of subadditivity along with (dis)economies of scale and scope. The quadratic cost model employed in this model is in the following form with total co The output, input, and cost shift variables all represent independent variables. Dependent and Output Variables The dependent variable in the quadratic equation is total cost In this quadratic model, electricity is modeled as an industry with two outputs rather than one. Different
46 authors have specified different pairs of outputs for use in this model. Kwoka in his 1996 and 2005 publications uses distribution and generation as the two outputs (Kwoka 1996 and Kwoka 2005) While this was useful in a nationwide study of utilities, it proved infeasible due to the structure of the electric ity market in Washington State. ~64% of electricity used in Washington in 2009 came from hydroelectric generation, compared to ~6% nationally in the year 2009 (Energy Information Administration 2010) This market difference is further accentuated by the p resence of the BPA. Most public utilities in Washington State purchase over 90% of their power from the BPA (Washington State Department of Commerce 2010) However, the BPA acts like a generating resource to the distribution utilities it sells to in a key way. The BPA sells electricity to its preference customers at cost. This is unlike the wholesale market, where profit maximizing occurs. In the last decade, Pacific Northwest electric utilities have increasingly entered the wholesale electricity market. In the early 2000s, The BPA introduced its slice m ethod of power sales. Under the slice method public utilities could get part or all of their electricity as a 'slice' of the federal system. In practice, this meant that a utility would agree to a long ter m contract (5+ years) to receive an agreed upon percentage of the BPA's total power output and then pay that same percentage of the BPA's generation costs. Due to fluctuation in water levels and stream flow, the amount of electricity varies every year, and as such utilities are responsible for purchasing electric power on the wholesale market in cases of shortfalls Utilities are responsible for selling excess electricity on the open market in the case of surplus (Bonneville Power Administration 2012) Gra ys Harbor PUD is one example of this. In the year 2000, it had total sales excluding sales for resale of over 1.1 million megawatts, but in the year 2009 sales
47 decreased to less than one million megawatts due to declining industrial activity in the wood products industry. However, under its slice product the PUD purchased over 1.7 million megawatts in the year 2009. It sold the surplus electricity on the spot market at profit maximizing prices rather than at cost. This is reflected in its annual report T he District is a SLICE cust omer of Bonneville, which means the PUD manages a small porti on of the Federal Hydroelectric System. While the productio n of the Federal system was off slightly compared to average the market price of power was significantly low er than in prior years. This resulted in a reduction of whol esale sales compared with 2008. (Grays Harbor PUD 2010) The Pacific Northwest electricity differs from other regional markets in the United Sta t es. The BPA is the largest wholesale marketer of e lectricity, but it sells power at cost, and not for profit. The region is also marked by hydropower usage, which has far lower variable costs than thermal generation. Due to these factors, a quadratic cost model using distribution and generation as the two outputs is inappropriate. Instead, a quadratic model using electricity distributed to residential and co mmercial customers and electricity distributed to industri al customers is used. Residential and commercial users are combined due to their similarit y. Both consume relatively small amounts of low voltage power on a per customer basis. Industrial users such as aluminum and other manufacturing plants receive much higher amounts of electricity on a per customer basis. Many industrial users also receive e lectricity directly from high voltage transmission line rather than the low voltage distribution lines used to serve residential and commercial customers. Not only do residential users have distribution lines, but in order to lower the voltage, substations are required. Also, each user regardless of size has it owns costs for billing and, in many cases, meter reading. This is one area where industrial users are less costly to serve than other users. Other
48 differences between industrial users and residenti al/commercial users include that industrial use of electricity is generally stable throughout the day, and as such, industrial users consume a larger percentage of their electricity during off peak times. Off peak demand is cheaper to serve as utilities ca n idle their more expensive power plants. In contrast, the usage of residential and commercial customers is conce ntrated during day time hours and is much more volatile as households and businesses use air conditioners and heaters to respond to weather co nditions (Greer 2011) Previous academic research has looked at the issue of separating electric generation into multiple outputs depending on th e class of output. Karlson separated electricity sales into residential, commercial, industrial and wholesale c lasses and found that separating them into separate outputs was appropriate (Karlson 1986) Other studies hav e shown a significant amount of multicollinearity between residential and com mercial users and as such, this study combines the two categories (Hay ashi et al. 1985 ) Wholesales sales (or sales for resale) are not considered in this study. The separation of industrial users and residential/commercial users is further reinforced by the ratemaking process. Both public utility commissions that regulat e rates for investor owned utilities and individual public utilities, which set their own electric rates, typically separate out costs for residential, commercial, and industrial customers. The different characteristics of each class discussed above are al so taken into the ratemaking process. Industrial customers are the only customer class that typically pays a demand charge. All customers pay customer charges that cover the cost of power lines, services and metering, and energy charges based on the total amount of energy used (billed in cents per kilowatt hour). Demand charges are used to recover other costs such
49 as new generating capacity, and they are usually billed based on the highest total kilowatt use over a fifteen minute period in the billing perio d. New generating facilities are often built to serve a utility's peak load. As industrial customers are the largest users of electricity, they are charged for their peak demand as well as total usage. This is done in order to reduce a utility's peak load when wholesale prices of electricity are at their highest. Output Variable Specification The variables Y1 for power distributed to r esidential and commercial users and Y2 for electricity distributed to industrial users both enter the equation individuall y as variables. However, as this is a quadratic cost model, both terms have a squared term enter the model as well. There is also an interaction term Y1*Y2 present in the model. By having these three additional terms in the model, this allows for a properl y specified cost function to emerge that has the previously discussed properties of a proper cost function. The use of a quadratic model allows for certain cost properties to emerge beyond the ones familiar in a linear model. For example, the signs of th e variables Y1 and Y2 both indicate monotonicity in inputs, one of the important attributes of a properly specified cost model. However, the inclusion of the squared terms (Y1^2 and Y2^2) allow for the emergence of product specific economies of scale as o pposed to ove rall economies of scale. T he interaction term Y1*Y2 allow for the emergence of economies of scope. The presence of economies of scope is obviously a key factor in looking at whether there are cost advantages to vertical integration in the elec tric utility industry. Product specific economies of scale are given by both squared terms (Y1^2 and Y2^2). In previous studies of the electric utilities, the expected sign of the terms has
50 traditionally been negative. This indicates the presence of some diseconomies of scale at some point in the electric utility industry and gives the resulting cost curves a convex shape. More complex measures can be taken to evaluate product specific economies of scale by calculating the average incremental cost o f a fir m and proceeding from there. The interaction term allows for economies of scope to arise in the cost function. Economies of scope are important to study in a multiple output industry as there could be cost advantages from the production of several outputs simultaneously such as splitting fixed cost among the multiple outputs. The presence of economies of scope in a multiple output industry characterized by cost complementarity can be used as an indication of a multiple output natural monopoly. The mathema tical definition of economies of scope arises from the concept that a single firm can produce the multiple outputs at a lower cost than two separate firms could produce those outputs. It should be noted that the regulated nature of the electric utility ind ustry could reduce the ef fect of economies of scope vis vis an unregulated free market. The expected sign of the interaction term Y1*Y2 is negative, which would indicate the presence of economies of scope for electric utilities that distribute electricit y to both indust rial and residential customers (Greer 2011) Input and Cost Shift Variables For quadratic cost models dealing with the electric utility industry, three input prices are usually included. These are purchased power cost, price of capital, and price of expenses. The price a utility pays for this electricity should obviously have a strong effect on its overall total cost. As such, the expected sign of thi s variable is positive. Since all utilities in this study are located in Washington State, all utilities purchase power from
51 the same spot market, so for short term power purchasing, there should be little expected variation. However, there is potential fo r significant variation among utilities with long term contracts to purchase power from Independent Power Producers and other electric utilities with surplus generating capacity. Of course, there should be little variation among most public utilities as w ell as most purchase the vast majority of their power from the BPA at equal Tier 1 rates (Bonneville Power Administration 2012) The price of capital is another important input. The price of capital is used to calculate the amount of capital costs that a re used in calculating total cost. Investor Owned Utilities and their trade organization, the Edison Electric Institute, have consistently charged that the lower average retail rates of publicly owned utilities are partially caused by unequal capital costs (Putham, Hayes & Bartlett 1994) This is due to the fact that publicly owned utilities borrow from the tax exempt municipal bond market, allowing them to offer lower interest prices on bonds than Investor Owned Utilities. According to the W ashington U tili ties and T ransportation C ommission Supplement, all three Investor Owned Utilities operating in Washington State also issued tax exempt bonds as well as more typical taxed corporate bonds; c ooperatives and some smaller, rural public utilities can also take advantage of low interest rate loans from the federal e three Investor Owned U tilities also use equity to finance capital costs, although in 2009 Puget Sound Energy ceased equity financi ng with its purchase by Macquarie Group and its subsequent delisting from the New York Stock Exchange in 2009 (Washington Utilities and Transportation Commission 2013) The expected sign of this input variable is positive, as a higher price of capital shou ld in theory lead to a higher overall total cost.
52 The third typical input price for electric utilities is the price of labor. This has been calculated various ways by different researchers. One of the most common ways has been to take total payroll expen se divided by either the total number of hours worked or by total full time equivalent employees. While the WPUDA sourcebook provided information for the number of full time equivalent employees, other data sources did not. Data for total payroll expense w as also unavailable for all utilities. Others have encountered similar problems with this input variable. Kwoka, whose data set consisted of 543 utilities located throughout the United States used average state manufacturing wage to account for the differ ing price of labor throughout states (Kwoka 1996) Since this data set consists only of utilities operating in one state, that way of accounting for the price of labor is useless. It should also be noted that almost every electric utility in Washington has collective bargaining agreements with one of three locals of the International Brotherhood of Electrical Workers (IBEW) (IBEW Local 77, 2012) These blue collar workers such as linemen represented by the IBEW represent one third to one workforce. As such there should be little variation in the price of labor among these workers. Of course, this does not rule out substantial variations in the price of labor among managerial workers for electric utilities. Howeve r, there is no data to te st this The lack of Full Time Equivalent (FTE) data for all utilities prevents even proxies for the price of labor to look at differing efficiencies among electric utilities in utilizing labor as an input. If price of labor were included as an input price, the expectation would be that its sign would be positive as a higher price of labor should theoretically lead to a higher total cost.
53 The last grouping of variables present in this quadratic cost model is cost sh ift variables Unlike the previous two groups of variables, the choice of cost shift variables varies widely throughout the literature. There are a variety of variables in the data set that could be used for this r ole. One will certainly be hydro in order to control for the amount of hydroelectric production a utility has in its fuel mix. The other cost shift variables will be shown in the following chapter.
54 Chapter 5 Results of the Econometric Model Description of Utilities in Data Set and Data Sources My data set consists of 26 electric distribution utilities operating in the State of Washington. Due to the difficulty of data collection, this is only about half of Washington State electric utilities. However, these utilities include the 12 largest utili ties in Washington and 19 of the largest 22 utilities. The data set includes about 92% of all utility customers in the State of Washington (Energy Information Administration 2010) All variables in this study are for the year 2009. More detailed informatio n about each utility is available in Table A.2. This study includes all three investor owned electric utilities operating in Washington State. These Are Avista Utilities 9 Puget Sound Energy 10 and PacifiCorp 11 est and large st electric utility. It serves eight counties along the Puget Sound in Western Washington, in addition to Kittitas County in Eastern Washington 12 Avista Utilities is the second largest IOU and serves 9 Formerly Washington Water Power Company 10 Formerly Pu get Sound Power and Light 11 Formerly Pacific Power and Light. Pacific Power and Light's corporate parent PacifiCorp acquired Utah Power and Light Company in 1987. Later, PacifiCorp was sold to Scottish Power in 2001, and subsequently to MidAmerican Energy Holdings Company, a subsidiary of Berkshire Hathaway, in 2006. 12 Jefferson County voters authorized Jefferson County PUD to offer electric distribution service in 2008. The County agreed to acquire PSE's electrical infrastructure in Jefferson County in 201 0. This study uses data from 2009, and so Jefferson PUD is not included as an electric distribution utility as it did not start providing that service until 2013.
55 Eastern Washington centered on its headquar ters in Spokane. It also serves Northern Idaho and 21 customers in Montana. Approximately 65% of its electric revenues come from customers in Washington State. PacifiCorp is the largest overall investor owned utility but has the smallest Washington custome r base and revenues of the three IOUs PacifiCorp serves several communities in Southeastern Washington, including Walla Walla and Yakima. Its parent company also serves customers in California, Oregon, Idaho, Utah and W yoming. Only about 7% s electric revenues come from Washington State (Washington Utilities and Transportation Commission 2013) This does not include its parent company, MidAmerican Energy Holdings Company, ownership of several distribution electric utilities in the Midwest and several non utility generating facilities as well as other energy companies operating in the Unite d States and a broad. Unlike PacifiCorp, Puget Sound Energy and Avista Utilities are vertically integrated utilities with natural gas utility operations in ad dition to being electric utilities. The competitive advantage or lack thereof of a company operating both natural gas and electric utilities is outside the scope of this study and will not be analyzed. Due to the regulated nature of these markets, separate financial and other data is available for just the electric utility part of a company. The sample also consists of 23 of the 59 public utility districts, municipals, mutuals, and cooperatives operating electric utilities in the state of Washington. First it should be noted that cooperatives are not studied in this thesis. While they are federally mandated preference customers, they are on average much smaller than other public utilities and investor owned utilities. The largest cooperative electric utili ty in
56 Washington Inland Power and Light, serves only 36,365 customers or only slightly over 1% of Washington's electric customers (Energy Information Administration 2010) This, coupled with the lack of available data on the federal and state level, led t o their exclusion from this study. Mutuals are also e xcluded from this study. Mutual electric utilities are similar to cooperatives but were created before the cooperatives were allowed. Mutuals are differ ent in that all property holders in the service are a own the mutual In contrast, cooperatives are owned by all customers regardless of property ownership. Mutuals also have limited data available on the state and federal levels. There are seven mutuals in Washington S tate. Peninsula Light Company is the l argest, but is only the 16 th largest electric utility Washington State. Public Utility Districts are the second largest grouping of utilities after investor owned utilities ( PUDs, mutuals, cooperatives, and municipal utilities on a whole serve more custom ers and distribute more electricit y in Washington State than IOUs) in terms of total customers. PUDs (called Peoples Utility Districts in Oregon) are a unique institution to the Northwest. PUDs are organized on the county level with most but not all servi ng as the sole electric utility in their county PUDs were established in the majority of Washington Counties by 1940. Currently, there are 28 PUDs serving 27 o f the 39 counties in Washington (Public Power Council 200 2) 13 Of these, only 23 PUDs are electri c utilities (the remaining PUDs serve as water and/or broadband telecommunications utilities only). Of these, Whatcom County PUD and Asotin County PUD each serve less than five industrial customers, and no residential customers. Due to their small size and limited scope, these two utilities are excluded from the study. The 13 Mason PUD #1 and Mason PUD#3 serve different service territories within Mason County
57 remaining 21 PUDs with residential electric distribution service are included in the st udy and are listed in Figure A.2 PUDs are concentrated in less populated counties as only 3 of the 11 largest counties in Washington have a PUD with electric service. The final type of public utility present in Washington is municipals. These are part of a city government but some also serve areas outside their city limits. Like all public utilities, t hey qualify as BPA preference customers. Seattle, Washington State's largest city, and Tacoma, the state's third largest, are both served by municipal electric utilities. Due to their large size, both Seattle City Light and Tacoma Public Utilities are incl uded in this study. Due to the lack of available data on the Federal and State level, no other municipals were included in this study. The largest excluded municipal, the City of Richland, served 23,599 customers in 2009, less than one percent of the total customers in the State of Washington (Energy Information Administration 2010) The final data set for this study consists of 23 public utilities (21 PUDs and 2 municipals) and three Investor Owned Utilities. Overall, they serve over 90% of electric cust omers in the state of Washington and over 88% of Total Electric Sales. Due to the fragmented nature of data on electric utility industry, several sources were used to populate the statistical database used for this thesis. The first source that was used for all utilities is Energy Information Agency form 861, particularly File 1 and File 2. This form provides basic statistics for all electric utilities (both public and private) in the United States such as number of customers overall and by sector, and o verall sales. Investor Owned Utilities are required to submit far more detailed information for Federal Energy Regulatory Commission (FERC) Form 1. This form is hundreds of pages long and has detailed statistics on every facet of an
58 electric utility from s tock dividends to ne w miles of transmission line. Multistate Utilities report information on a whole utility rather than state by state basis However, each utility must file a Washington supplemental report with the Washington Utilities and Transportati on Commission (WUTC) which breaks down key statistics such as total cost and total revenue only for the portion of a company serving as an electric utility in Washington State. These statistics are compiled by the WUTC and are released annually as The An nual Statistics of Electric Companies. The latest edition for the years 1999 2011 was released in January 2013. At the time of data collection, the latest sourcebook only covered through 2009, so year 2009 data was used. Other Washington State governmen tal agencies provide electric utility data. Washington State began requiring that all electric utilities operating in the state begin reporting th eir fuel mix disclosure beginning in the year 2000. This program is administered by the State Energy Office wi thin the Department of Commerce. The state as a whole receiv ed 64% of its electricity from hydroelectric sources, 17% from c oal, 11% from natural gas, 4% from nuclear, 2% from c ogeneration and less than 1% each from the remaining sources in the year 2009 ( Washington State Department of Commerce, 2010) While public utilities are not under the purview of a utilities regulator such as the WUTC, they still must submit audited financial reports to the Wash Office Most are conducted by th e Washington State public
59 utilities used private accountants for their financial audits 14 These reports only contain financial data and are of limited use for production statistics. For non financial statistics, I had to turn to self reported utility data. The most comprehensive was the Washington Public District Association Sourcebook. All Public Utility Districts with the exception of Snohomish County PUD, are members of the association. It produces an annual statistical handbo ok available on request. All data was self reported, and there were obvious discrepancies in the data, especially among the utilities that own generating facilities. For these utilities, annual reports released by the utilities were used to supplement data from the Washington Public Utility District Association 15 Ann ual reports were also used for other public utilities with generation facilities Statement of the Econometric Model In this study, the quadratic cost model regression below will be used to te st the effect the preference clause has on the electric utility industry in the BPA's service area in the Pacific Northwest by focusing on the aforementioned utilities in Washington State. This quadratic model is similar to ones employed previously by Gree r (Greer 2011). Equation 5.1 Regression Equation 14 G rant County PUD, Klickitat County PUD, Lewis County PUD, Okanogan County PUD, Seattle City These reports are available by request from the individual PUDs 15 These supplemental annual reports were particularly useful for the Mid C PUD's (Douglas County PUD, Chelan County PUD, and Grant County PUD) that own five dams on the middle section of the Columbia as well as Clark County PUD, which owns the natura l gas fired River Road Generating Plant.
60 The multiple outputs used in this study are Y1 electricity distribution to residential and commercial users and Y2 electricity distribution to industrial users. As this is a quadratic cost model, bot h have squared term s (Y1^2 and Y2^2 ) that show product specific economies of scale. The interaction term (Y1*Y2) shows economies of scope. There are also two input variables: the price of purchased power (PP) and the price of capital (PK). These output an d input variables are specified by the literature and are described in more detail in chapter 4 However, there a wide variety of possible cost shift variables to use in this study. These are characteristics that should have significant effect on total co st that are not given by the two outputs and three inputs. For this study, three cost shift variables are used in the final regression while the dataset includes other cost shift variables that were not used in the final regression. Information on omitted variables is included in Appendix B. The first and most apparent cost shift variable is hydroelectric power. Hydropower is used as a cost shift variable by Kwoka (Kwoka 2005) Other studies comparing the efficiency of public and private utilities have excluded utilities with hydroelectric generating plants due to their lower c osts (Koh et al. 1996 ) The Northwest generates more hydroelectric power and a higher percentage of its electricity comes from hydroelectricity than any other state in the nation. This hydroelectricity is not allocated evenly. The preference clause is used as a rationing agent of federal hydropower resources, and as such, public utilities and cooperatives receive a much higher percentage of their total electricity used for distribu tion from hydroelectricity. Hydroelectric generation has lower costs than any other type of generation This is due to the fact that hydroelectric dams require no fuels, little maintenance, and little personnel to run,
61 although they do have high intial cap ital costs. All of the dams on the main stem of the Columbia and its main tributaries, the Snake River and the Clark Fork with power marketed by the BPA date to a four decade period from 1935 to 1975 (Norwood 1981) As such, these dams have paid off most o r all of their capital costs and still have a long lifespan to generate power. Due to the fact that hydropower is lower in cost than alternative modes of generation, the expected sign of the variable hydro should be negative as increasing percentage of hy dropower used by a utility should lower its total costs. The next cost shift variable used in the final regression is BPA, which represents the total percentage of electricity distributed to end users that came from the BPA. This variable has no preceden ce in the literature as no one has done a study using the preference clause to help evaluate the efficiency of public and private efficiencies. As the BPA is oversubscribed for the amount of power it produces, the preference clause is currently used as a r from hydroelectric dams. The BPA markets the output of the sole nuclear generating plant in the Pacific Nor thwest, the Columbia Generating Station, which is operated by Energy Northwest 16 The agency also purchases power on the spot market as hydropower production fluctuates seasonally and year to year as river flows fluctuate. In the year 2009, ix consisted of 84% h ydropower, 9% nuclear power with the 16 Formerly known as the Washington Public Power Supply System (WPPSS) Energy Northwest is joint operating agency operated by the 23 public utilities in this dataset along with municipal utilities in Richland, Cent ralia, and Port Angeles as of the year 2009.The BPA is still also paying off the construction costs of the never finished and moth balled net billed nuclear plants WNP 1 and WNP 3 For more on Energy Northwest, see Pope, Daniel and Schueler, Willis
62 remaining 7% consisting of small amounts of thermally generated and renewable electricity (Washington State Department of Commerce) The expected sign of the variable BPA is negative as preference c ustomers should have lower costs due to being a public utility even after controlling for the amount of hydroelectric power received. The final cost shift variable used in the final regression is total number of customers. This variable comes from Kwoka ( Kwoka 2005). According to him, the amount of customers increases both administrative and production costs because each non industrial customer needs to have the voltage of the electricity it receives down gauged. As such, the expected sign of customers is positive. In the final regression, the two output variables (Y1 and Y2), their squares (Y1^2 and Y2^2), their interaction term (Y1*Y2), the two input variables (PP and PK), and the three cost shift variables specified above (HYDRO, BPA and CUSTOMERS) are used in the quadratic cost function. Description of Variables The dependent variable for this regression and for all quadratic cost models is total cost Total Cost is calculated the same way for Investor Owned Utilities and Public Utilities only u sing different forms. This data comes from the WUTC Washington supplemental form for IOUs and from the WPUDA sourcebook and individual annual reports for public utilities. First, total operating costs including depreciation and taxes were calculated. Next, total taxes were subtracted to get Total Operating Costs minus Taxes While this model seeks to compare investor owned and public utilities performance regardless of taxes, think tanks for both types of utilities have published papers claiming tax advanta ges for each type. Investor owned utilities claimed that public
63 utilities get an unfair advantage by being excluded from income taxes. Although many states have taxes designed to compensate for this such as the Privilege tax in Washington State P ublic ut ilities claim that accelerated depreciation schedules and other tax advantages are given to IOUs under the federal income tax structure (Energy Information Agency, 2010) Finally, capital costs are added to get total cost. Capital cost is derived by mult iplying the price of capital by net electric plant. Net electric plant is given by the audited financial reports for public utilities and by the WUTC Washington supplement. Price of Capital is calculated differently for public and private utilities. For pu blic utilities, interest on long term debt (almost entirely from bonds, although a few smaller PUDs received loans from the U.S. Department of Agriculture's Rural Utilities Service and the Washington State Department of Commerce's Community Economic Revita lization Board) and amortization expense on long term debt are summed and then divided by total long term debt outstanding at the beginning of 2009 17 For Investor Owned Utilities, I attempted to use the Weighted Average Cost of Capital (Hayashi et al, 198 5) Weighted Average Cost of Capital is defined as the weighted average cost of common stock, preferred stock, and long term debt. However, Avista Utilities is the only publicly traded company that this data is available for in Washington State. The distri bution arm of PacifiCorp in Washington is Pacific Power, a subsidiary of PacifiCorp. PacifiCorp itself is a subsidiary of MidAmerican Energy Holdings which is a subsidiary of Berkshire Hathaway. Puget Sound Energy was bought 17 Long Term Debt outstanding at the end of 2008/Beginning of 2009 is used because Several PUDs issued large bond issues during the year of 2009, which they had not begun paying interest on. One example is Pend Oreille County PUD, whose long term debt increased o ver 350% in the year 2009 due to a $70+ million bond issue to retrofit the PUD's Box Canyon Dam.
64 in the year 2009 by Macquarie G roup, an Australian investment banking and financial services firm under the aegis of a newly created U.S. Subsidiary Puget Holdings. This private takeover of Puget Sound Energy has resulted in the inability to calculate its weigh ted average cost of capit al for lack of lack of relevant data. As a substitute for weighted average cost of capital, I have used the rate of return the WUTC allowed all three private utilitie s to receive in the year 2000 which was 8.25%. While not exact, this is a reasonable appro ximation of the price of capital it needs to raise funds in the financial market from equity and bonds. Purchased Power Cost (PP) is sourced from the WUTC Washington Supplement for Investor Owned Utilities, and from the WPUDA sourcebook and individual a nnual reports. The units are dollars per megawatt hours. The price of purchas ed power comes from the cost of purchased power divided by the total amount of purchased power. To tal Distribution to end users is a variable given in million megawatt hours (MW h x10 6 ). It is the total amount of power distributed to end users. It might be less than total reported electricity generated and electricity purchased depending on how the utility accounts for line losses in transmission and distribution. Data from EIA F orm 861 is used for the total amount of power distributed to all end users including residential and commercial customers (Y1) and total distributed to industrial customers (Y2) The next variable is total customers. It is important to note that electric u tilities only know how many meters (customers) they serve as opposed to total number of people. This data comes from EIA Form 861 File 2. This customer data is further subdivided into total residential, industrial and commercial customers.
65 Previous stud ies have hypothesized that hydroelectric power has lower costs than other forms of generation while nuclear and newer renewable generation have higher costs. Due to m ulticollinearity the only included variable is hydro. Hydro shows what percent of a utili The data comes from the Washington Department of Commerce Fuel Mix Report 18 The last variable included in this study is percentage of electricity received from the BPA. The BPA is responsible for marketing a nd transmitting preference power in the Northwest and as such, its power is effectively rationed out by the preference clause. The percentage of total distributed power from the BPA is derived from the Department of Commerce Fuel Mix Report. All public ut ilities in this data set with the exceptions of Chelan County PUD and Douglas County PUD, who both operate large hydroelectric dams on the Columbia River, receive preference for hydroelectric power marketed by the BPA. In comparison, the only Investor Own ed Utility to receive power from the BPA was PSE, which only received 3% of its power from the BPA (Washington State Department of Commerce 2010) This cursory look at this statistic shows that the preference clause has turned into a rationing agent that r eserves almost all hydropower to public utilities. This is shown by the tables of descriptive statistics below. Public Utilit ies in this data set received on average 83.58% percent of electricity from hydroelectric power, while IOUs receive d 40.62% of elec tricity from hydroelectricity on average 18 Kittitas County PUD did not report its fuel mix to the Department of Commerce in 2009. However, according to its annual report it remained a full requirement s customer of the BPA as it was in 2008. Therefore, I assigned it the same percentage values as other BPA full requirements customers such as Ferry County PUD, Skamania County PUD, and Wahkiakum County PUD
66 Table 5.1 Data Set Descriptive Statistics TOTALCOST Y1 Y2 PK PP HYDRO BPA CUSTOMERS Mean 2.54 2.32 0.65 5.33 33.06 78.72 67.18 113156.2 Median 0.69 0.69 0.29 4.98 31.30 83.89 81.37 31795.5 Maximum 21.12 20.7 2 3.72 8.25 65.80 100 100 1072811 Minimum 0.03 0.04 0.00 0.00 18.89 34.76 0 2403 Observations 26 26 26 26 26 26 26 26 Table 5.2 Public Utility Descriptive Statistics TOTALCOST Y1 Y2 PK PP HYDRO BPA CUSTOMERS Mean 1.53 1.38 0.61 4.95 30.96 83.68 75.80 65619.70 Median 0.58 0.62 0.25 4.92 30.92 83.89 88.92 30030.00 Maximum 6.86 8.51 3.72 8.21 41.32 100.00 100.00 394731.00 Minimum 0.03 0.04 0.00 0.00 18.89 54.09 0.00 2403.00 Observations 23.00 23.00 23.00 23.00 23.00 23.00 23.00 23.00 Table 5.3 IOU Descriptive Statistics TOTALCOST Y1 Y2 PK PP HYDRO BPA CUSTOMERS Mean 10.27 9.55 0.97 8.25 49.15 40.63 1.05 477602.7 Median 6.11 4.76 1.02 8.25 41.20 36.11 0 233332 Maximum 21.12 20.72 1.15 8.25 65.80 51.01 3.14 1072811 Minimum 3.59 3.17 0.75 8.25 40. 46 34.76 0 126665 Observations 3 3 3 3 3 3 3 3 Regression Results The above equation specified previously was used to estimate a quadratic cost model of twenty six Washington State electric utilities that are part of the BPA service area. All of these utilities are subject to the preference clause rationing their access to inexpensive hydropower marketed by the BPA. The results of this equa tion was estimated using Eviews and are reported below.
67 Table 5.4 Regression Results Dependent Variable: TO TALCOST Method: Least Squares Sample: 1 26 Included observations: 26 Variable Coefficient Std. Error t Statistic Prob. C** 2.276674 1.006515 2.261938 0.0390 Y1 0.425414 0.284381 1.495926 0.1554 Y2* 0.927246 0.49964 8 1.855799 0.0832 Y1^2* 0.009965 0.004277 2.330165 0.0342 Y2^2 0.031395 0.121071 0.259310 0.7989 (Y1*Y2)*** 0.495400 0.155862 3.178454 0.0062 PK 0.042577 0.054032 0.787987 0.4430 PP 0.006579 0.017901 0.367503 0.7184 HYDRO** 0.015817 0.006295 2.512492 0.0239 BPA** 0.007498 0.002788 2.689641 0.0168 CUSTOMERS*** 1.66E 05 4.89E 06 3.400486 0.0040 R squared 0.996070 Mean dependent var 2.535239 Adjusted R squared 0.993450 S.D. dependent var 4.335724 S.E. of regression 0. 350897 Akaike info criterion 1.039457 Sum squared resid 1.846925 Schwarz criterion 1.571728 Log likelihood 2.512936 Hannan Quinn criter. 1.192732 F statistic 380.1851 Durbin Watson stat 2.158224 Prob(F statistic) 0.000000 T he R squared value of above .99 indicates that this model explains 99 percent variability of total cost among the small sample of 26 Washington State utilities used in this study. While this number is very close to 1 (with 1 being a duality of the two expr essions), there is empirical support for very high R squared for a quadratic cost model of electric utilities. Both Kwoka and Greer have R squared values above .96 in their published articles using quadratic cost functions (Kwoka 2005 and Greer 2011) The F Statistic also supports the results of the R squared. The F Statistic of 380.1851 shows a
68 zero probability that the group of variables use d to estimate this regression are not together jointly significant. Still, the R squared number is suspiciously hig h for a data set with only 26 utilities. This is a very small sample size. It is also an unbalanced sample with twenty three public utilities, and only three IOUs. Other reasons for this could include multicollinearity. As such, a table of correlation coef ficients is included in Appendix A as Table A.1 However, The Durbin Watson Statistic of 2.15 indicates that this data set is not serially correlated. The White Test was used to test for heteroscedasticity. With only 26 utilities in the data set, the data It should also be noted that not all variables used in this regression are significant. Four of the variables are not significant at a 90 percent confidence level, and 5 are not significant at a 95 pe rcent confide nce level. Only two variables are significant at a 99% confidence interval. These results are of course affected by the small sample size of only 26 utilities. Of the five output variables in this regression, only two were significant at a 95 percent confi dence interval. Also, one variable did not have its a priori expected sign. The variables Y1 and Y2 are positive with coe fficients between zero and one This means that total cost increases with output, but at a declining rate. This is in accord with prope rly specified cost models. However, both have p values above .05, and as such, are not statistically significant at all. The squared term for Y1 had a coefficient of 0.009965, which indicates very slight diseconomies of scale in the production of electric ity for residential and
69 and results from similar studies. One possible explanation is in similar input prices. Under the Pacific Northwest Electric Power Planning and C onservation Act of 1980, Investor Owned Utilities that had higher Average System Costs utilities could receive some of the benefits of the inexpensive hydroelectric power marketed by the BPA. Under the residential exchange program, IOU received payments from the BPA to be passed on to residential and small farm ratepayers in their bill in order to narrow the gap between IOU and public utility rates Purchased power is by far the largest input in distributing electricity with around 60 utilities in the BPA service area receiving purchased power for residential users at near equivalent rates. Due to these unique market conditions, it is possible that there are no economies of scale in electricity produ ction and distribution. Of course, this is dependent on how the IOU lists the residential exchange payments from the BPA in their audited financial statements. If it is listed as revenue, this would have no effect due to this model focusing solely on costs and not revenue. If it subtracted from purchased power costs, the above could be one explanation for the presence of diseconomies of scale. The squared term of Y2 is negatively signed show ing economies of s cale in electric power output to industrial cust omers This is in accord with expectations and other articles in the field. Since the residential exchange program only applies to residential and small farm customers and not industrial customers, it could be an explanation for why there are economies of scale for industrial users but not residential and commercial users. It should also be noted that the Y2^2 term was statistically insignificant with a p value of .7989.
70 T he interaction term Y1*Y2 is highly significant with a probability above 99 percent. It is also has a negative sign as expected a priori. This indicates that there are economies of scope in producing electricity to industrial customers as well as residential/commercial customers. This is also supported by the literature. The input variabl es also differed from a priori expectations. Both the price of capital and the price of purchased power were statistically insignificant Their sign s also differed from a prior i expectations in fact that they were negative This is surprising because it ap pears to show that increasing the price of capital and purchased power would lead to lower total costs. However, the values are statistically insignificant from zero, so the negative values should be disregarded. The price of purchased power might be insig nificant due to all of the utili ties coming from the same state and purchasing from the same spot market. The price of purchased power does include power purchased from the BPA. If prices on the spot market tracked BPA wholesale prices, this could be true If the utilities truly did pay very similar prices for electricity, the variable might be insignificant. As for the price of capital, it is surprising that it has no significant effect. Public utilities have an adva ntage in the price of capital because th ey are to issue all debt in tax exempt bonds. However, it should be noted that capitals costs are a small portion of total costs relative to operating costs, so that could be driving the insignificance of the price of capital. Unlike similar models, this m odel does not include the price of labor as an input variable due to the lack of data. The three cost shift variables did meet a priori expectations in terms of signs and significance. Similar to Kwoka, the variable customers had a positive sign (Kwoka 20 05)
71 It also was statistically significant at over a 99% confidence level. This indicates utilities with more customers face higher costs. The variables BPA an d hydro were also significant at an over 95% confidence level. They were also both signed negati ve, which accords with the a priori expected sign fuel mix is expected to decrease total cost. Investor Owned Utilities have three main arguments explaining publi c utilities federal income taxes. This model accounts for this by excluding taxes from the cost function all together. The second is that public utilities are able to issue tax exempt bonds to finance their debt while IOUs must resort to taxed bonds and equity financing. The data bears this out. Out of the 26 utilities in the dat a set, the three IOUs have the second, third, and fourth highest prices of capital. This study attempts to control for that differential by including the price of capital as an input variable and including capital costs in the total cost. The third is that public utilities have lower costs due to preferential access to federally generated hydr oelectric power. This study focuses on that third aspect. The results of the regression show that an increased amount of hydro electric power in fuel decreases total cost as shown by the negative sign on the variable hydro. As BPA hydroelectric power is cur rently rationed by the preference clause, public utility preference customers gain a larg er share of hydroelectric power and consequently lower total costs Now that, has been controlled for the BPA variable can be suitably analyzed. As the preference clause works as a rationing agent for federal hydroelectric power based on whether the customer is a
72 public utility or not, this variable can attempt to explain if public utilities achieve lower cost s than Investor Own ed Utilities. According to this regression they do. The negative sign of the coefficient indicates that the public utility preference customers have a lower total cost than Investor Owned Utilities operating in the State of Washington. This becomes apparent after controlling for the amount of hydroelectric power a utility receives. This indicates public production of electricity is more efficient than private production among these utilities. While some arguments in favor of the prefe rence clause focus on the cost advantages of a public utility, it is important to note that there are other arguments in favor of the preference clause. One is that the existence of public power utilities allows for yardstick competition between them and I OUs. The rates and costs of the public Pacific Northwest. Similarly, the existence of BPA preference power with provisions f or new loads under 50 megawatts also encourages attempts at the creation of new utilities. In 2008, voters in Jefferson County, Washington approved a ballot measure allowing the Jefferson County PUD to ent er the electric business (WIP News Service 2012) After purchasing the assets of the investor owned Puget Sound Energy in Jefferson County, the PUD began electric distribution service in 2013 as a BPA full requirements customer. A similar effort in Thursto n County in 2012 failed. The existence of a low cost power supply in the event of a PUD takeover or municipalization can also serve as a yardstick. Public utilities also have greater opportunities for local control than IOUs PUDs in Washington State are run by 3 elected PUD commissioners. A municipal utility is
73 overseen by an elected City Council and Mayor. Cooper atives and m utuals are overseen by an elected Board of Directors drawn from the membership in the cooperative or mutual. This is not the case fo r Investor Owned Utilities. The Board of Directors of the IOUs is responsible to their owners. In the case of Puget Sound Energy, it is an Australian financial services firm. PacifiCorp is a subsidiary of MidAmerican Energy Holdings, which is a subsidiary of one of the largest companies in the world, Ber kshire Hathaway. In contrast responded to the desires of the people they serve. (White and Freeman 1985, 28) In light of the lower cos ts of public utilities found in the regression and other non economic factors identified above, the preference clause is an appropriate way of allocating scare federal hydroelectric resources in the BPA service area in the Pacific Northwest. The existence of federal hydroelectric power and the preference clause have helped in the formation of all 21 PUDs in this study. These PUDs and the two municipals in the data set as preference customers distribute this low cost hydroelectric power at lower costs than c ompeting IOUs. Furthermore, t hey also provide a useful yardstick in measuring the performance of IOUs with attendant anti monopoly benefits. They also offer the benefit of local control unlike IOUs. When the preference clause was first written into law in 1906, it permanently affected the United States electricity market, nowhere more so than the hydropower rich Pacific Northwest. Under the aegis of the BPA, the preference clause has helped electrify a region, and after that was completed, ensured electrici ty flowed to more efficient public utilities that provided yardstick competition to Investor Owned Utilities.
74 Chapter 6 Conclusion The existence of the preference clause has forever altered the electricity market in the Pacific Northwest. It led to the rise of public utilities throughout the state that depend on hydroelectric power marketed by the BPA for the vast majority of their electric load. While all three IOUs in Washington State own hydroelectric ge nerating facilities, all twenty three public ut ilities received a higher percentage of their electric load from hydroelectric power than the three IOUs. This along with the fact that only one of the three received power from the BPA (Puget Sound Energy received slightly over 3% of its electric load fro m the BPA (Washington State Department of Commerce 2010) ), show s the preference clause to be a rationing agent. The effects of rationing under the preference clause are examined throughout this thesis. The second chapter of this thesis dealt with the his torical development of the BPA, and the Pacific Northwest electricity market. The effects of rationing become apparent in the 1970 Basin began operation in 1975. While in previous decades there was a surplus of electricity available for sale to IOUs, this surplus quickly dwindled. Only the Pacific Northwest Power Planning and Conservation Act of 1980 could avert regional strife over whether Washington State was getting more than an equita ble share of BPA resources by having a higher percentage of customers served by public utilities and cooperatives.
75 Under the Act, residential and small farm customers received credits on their bill paid for by the BPA and transmitted by their distribution IOU as a compromise in equitably sharing the hydroelectric power resources of the BPA. The preference clause has remained intact in the three decades since then. The third chapter was a literature review of existing literature on the ownership effects of public utilities and the history of the preference clause. Academic studies on ownership effects of electric utilities have had inconclusive results M ultiple studies show that public utilities have lower costs and like wise, multiple studies how that priv ate utilities have lower costs. Other studies show no ownership effects at all The section on the preference clause looks at the preference clause on a national scale by examining legislation and court cases that have affected it since its inception in 19 06. The fourth chapter introduced the theoretical model used in the thesis. The model is a quadratic cost model. The model has dual outputs: electricity distributed to residential/commercial users and electricity distributed to industrial users. It also h as squared and interaction terms to look at economies of scale and economies of scope. In addition, there are two input variables, and three cost shift variables. The fifth chapter described the data set and the results of the regression of the quadratic cost model. The data set consists of 26 of the 62 electric utilities operating in Washington State including all 3 IOUs, all 21 PUDs, and 2 municipals. Combined, the utilities served over 90% of the electric customers in Washington State, and distributed o ver 88% of the electricity distributed in Washington S tate. The quadratic cost model show ed that hydroelectric power conferred preferentially to public utilities did lower costs. After controlling for the amount of hydroelectric power, the price of capital and
76 excluding taxes, there was a negative ownership effect of Public Utilities showing that public utilities engaged in electric production have lower costs than comparable Investor Owned Utilities. There are several ways this study could be improved f or future research. One is to include more utilities either in Washington State or throughout the entire BPA service area. There are over 100 utilities operating in the Service Area. Data for the Investor Owned Utilities PacifiCorp and Avista would be more useful as one could use the more detailed FERC Form 1 for the entire utility rath er than relying on Washington only data from the WUTC Data could also encompass multiple years. Much of the data used in this study goes back to at least the year 2000, and many earlier. The data itself could be improved by better more accurate data sources. Much of the data is self reported, and could differ significantly from utility to utility. One could also Data Envelopment Analysis to study the ownership effects in ele ctric utilities rather than using cost modeling. A new use for quadratic cost models would be to look at the effects of Initiative 937 in Washington. This initiative mandated utilities in Washington State with greater than 25,000 customers have a fuel mi x of 15% renewables by 2020 not including hydroelectric production ( except for efficiency upgrades to utility owned hydroelectric dams ) conducted looking at the effects of these larger utilities to purchase renewable energy (mostly in the form of wind energy) and compare their cost models to smaller utilities exempt from the requirement. This mandate in Washington and a similar one in Oregon have already changed the Northwe st po wer market. In spring, when hydroelectric
77 production peaks yet is operationally co nstrained by fish runs, wind power production also peaks. Starting in 2011, the BPA has given away power over the intertie at high production, low demand times in the sp ring. Even with this, the BPA has forced some wind generation facilities to shut down completely during high production, low demand times (Bonneville Power Administration) The effects of renewables so far are small, but as federal hydropower resources re main constant and renewable standards increase, they will become an increasing part of the power supply. A quadratic cost model would be appropriate to measure the effects of this change in fuel mix.
78 Appendix A Additional Data Table A.1 Correlation Coeff icients TOTAL COST Y1 Y2 Y1^2 Y2^2 Y1*Y 2 PK PP HYD RO BPA CUST OMERS TOTAL COST 1.000 0.991 0.301 0.935 0.098 0.965 0.467 0.782 0.647 0.512 0.989 Y1 0.991 1.000 0.253 0.945 0.054 0.972 0.434 0.798 0.603 0.466 0.997 Y2 0.301 0.253 1.000 0.147 0.937 0.426 0.106 0.070 0.163 0.229 0.251 Y1^2 0.935 0.945 0.147 1.000 0.010 0.930 0.364 0.776 0.540 0.373 0.950 Y2^2 0.098 0.054 0.937 0.010 1.000 0.244 0.039 0.175 0.002 0.027 0.058 Y1*Y2 0.965 0.972 0.426 0.930 0.244 1.000 0.370 0.700 0.545 0.42 9 0.973 PK 0.467 0.434 0.106 0.364 0.039 0.370 1.000 0.421 0.477 0.566 0.424 PP 0.782 0.798 0.070 0.776 0.175 0.700 0.421 1.000 0.592 0.342 0.787 HYDRO 0.647 0.603 0.163 0.540 0.002 0.545 0.477 0.592 1.000 0.375 0.589 BPA 0.512 0.466 0.229 0.373 0.027 0.429 0.566 0.342 0.375 1.000 0.436 CUST OMERS 0.989 0.997 0.251 0.950 0.058 0.973 0.424 0.787 0.589 0.436 1.000
79 Table A.2 Listing of Utilities Utility Type of Utility Cust omers (State of WA) Primary Service Area Year Founde d Total Electricity Distributed Average Retail Rate ( ¢/kWh) 19 Avista IOU 233,332 Adams, Asotin, Ferry, Grant, Lincoln, Pend Oreille, Spokane, Stevens, and Whitman Counties along with portions of Idaho and 21 customers in Montana 1889 5.509742 8.31 Benton County PUD PUD 47,074 Benton County (excluding City of Richland) 1934 1.726341 5.09 Chelan County PUD PUD 47,323 Chelan County 1936 1.655070 3.13 Clallam County PUD PUD 30,030 Clallam County (excluding the City of Port Angeles) and Western Jefferson Coun ty 1944 0.762661 6.29 Clark County PUD PUD 183,015 Clark County 1938 4.533034 7.44 Cowlitz County PUD PUD 48,197 Cowlitz County 1936 4.625321 3.99 Douglas County PUD PUD 18,254 Douglas County 1935 0.667641 2.27 Ferry County PUD PUD 3,394 Ferry County 1 936 0.091148 6.51 Franklin County PUD PUD 22,860 Franklin County 1934 0.972054 6.01 Grant County PUD #2 PUD 45,576 Grant County 1938 3.715666 3.11 Grays Harbor County PUD PUD 41,714 Grays Harbor County and Western Jefferson County 1938 0.979126 6.87 Ki ttitas County PUD PUD 4,256 Kittitas County 1936 0.084029 7.83 Klickitat County PUD PUD 11,954 Klickitat County 1938 0.326729 6.50 Lewis County PUD PUD 30,957 Lewis County 1936 0.933660 4.74 Mason County PUD #1 PUD 5,143 Mason County (Skokomish Valley a rea) 1934 0.070297 8.32 19 Average retail rate is from EIA Form 861
80 Mason County PUD #3 PUD 32,634 Mason County (excluding Skokomish Valley) 1934 0.660405 7.01 Okanogan County PUD PUD 20,495 Okanogan County 1936 0.637232 4.75 Pacific County PUD #2 PUD 17,091 Pacific County 1937 0.298191 6.88 Pac ificorp IOU 126,665 Benton, Columbia, Garfield, Walla Walla, and Yakima Counties along with portions of California, Idaho, Oregon, Utah, and Wyoming. 1910 4.183739 6.40 Pend Oreille County PUD PUD 8,732 Pend Oreille County 1936 0.969589 3.45 Puget Sound Energy IOU 1,072,811 Island, Jefferson, King (excluding Seattle), Kitsap, Kittitas, Pierce (excluding Tacoma), Skagit, Thurston, and Whatcom Counties 1885 21.866448 9.24 Seattle City Light Municipal 394,731 City of Seattle 1895 9.693424 6.83 Skamania Cou nty PUD PUD 5,772 Skamania County 1939 0.129723 6.41 Snohomish County PUD PUD 319,467 Snohomish County and Camano Island 1936 6.846237 7.45 Tacoma Public Utilities Municipal 168,181 City of Tacoma 1893 4.824116 5.64 Wahkiakum County PUD PUD 2,403 Wahkia kum County 1936 0.041593 7.23
81 Table A.3 Included Variables Data Utility Total Cost Y1 Y2 PK PP Benton PUD 1.1736022 1.260163 0.466178 4.2434519 35.008841 Chelan PUD 2.3022459 1.275853 0.359225 5.5514448 34.533333 Clallam PUD 0.448489 0.622521 0.140 14 3.951476 31.383535 Clark PUD 4.9417608 3.791616 0.741418 5.0901017 30.915514 Cowlitz PUD 1.9709018 1.175288 3.718546 4.8316627 30.310346 Douglas PUD 0.7035723 0.602115 0.065526 5.9798653 31.22604 Ferry PUD 0.0671583 0.048012 0.043136 8.2110063 26.94 3216 Franklin PUD 0.6715472 0.683384 0.288101 4.4054109 36.385758 Grant PUD #2 2.5390375 1.554511 2.138832 5.0002199 18.886165 Grays Harbor PUD 1.2080304 0.827057 0.152069 4.9234724 38.667277 Kittitas PUD 0.0605866 0.07728 0.006746 4.4883197 31.493734 Klickitat PUD 0.4189827 0.266745 0.059984 4.9643473 41.318662 Lewis PUD 0.5760611 0.688336 0.245325 5.942583 31.496681 Mason PUD #1 0.0661101 0.070297 0 4.3513073 27.21914 Mason PUD #3 0.456289 0.619711 0.040694 5.1005157 29.296186 Okanogan PUD 0.4108 376 0.596297 0.040935 5.1651368 26.181741 Pacific PUD #2 0.2107693 0.276688 0.021503 4.5662635 28.775081 Pend Oreille PUD 0.5423965 0.209966 0.759622 6.6815922 23.260219 Skamania PUD 0.0843255 0.101293 0.28373 4.1635237 29.260599 Snohomish PUD 6.224189 4 6.038829 0.833967 7.1323657 40.741783 Wahkiakum PUD 0.0258606 0.041593 0 0 28.23233 Seattle City Light 6.8599691 8.509578 1.183258 4.6785257 40.255645 Tacoma Public Utilities 3.1362687 2.310442 2.50026 4.4098675 20.223383 Puget Sound Energy 21.117064 20.71995 1.146499 8.25 65.804897 Avista 6.1117187 4.760596 0.749146 8.25 41.202017 PacifiCorp 3.5884413 3.166435 1.017303 8.25 40.457063
82 Table A.3 Continued Utility Hydro BPA Customers Benton PUD 78.03 88.9182 47074 Chelan PUD 94.98 0 47323 Clalla m PUD 83.89 100 30030 Clark PUD 54.09 62.011079 183015 Cowlitz PUD 82.86 82.879715 48197 Douglas PUD 100 0 18254 Ferry PUD 83.89 100 3394 Franklin PUD 76.37 79.859324 22860 Grant PUD #2 76.59 43.837002 45576 Grays Harbor PUD 86.87 100 41714 Kittita s PUD 83.89 100 4256 Klickitat PUD 83.89 100 11954 Lewis PUD 83.23 98.367841 30957 Mason PUD #1 83.89 100 5143 Mason PUD #3 83.1 99.009653 32634 Okanogan PUD 87.06 73.828193 20495 Pacific PUD #2 81.87 97.592098 17091 Pend Oreille PUD 95.96 16.092459 8732 Skamania PUD 83.89 100 5772 Snohomish PUD 77.61 78.32591 319467 Wahkiakum PUD 83.89 100 2403 Seattle City Light 91.22 47.451709 394731 Tacoma Public Utilities 87.64 75.324379 168181 Puget Sound Energy 36.11 3.1419388 1072811 Avista 51.01 0 233 332 PacifiCorp 34.76 0 126665
83 Tables A.4 A.10 Mean, Median, Maximum, and Mininium of Total Cost by Independent Variables. Table A.4 Y1 Total Cost Y1< .5 Million MWh Y1 .5 Million to 1 Million MWh Y1 1 Million to 4 Million MWh Y1> 4 Million MWh Mean 0.184524 0.639261 2.807465 10.07824 Median 0.075742 0.576061 2.539038 6.542079 Maximum 0.542396 1.20803 4.941761 21.11706 Minimum 0.025861 0.410838 1.173602 6.111719 Observations 8 7 7 4 Table A.5 Y2 Total Cost Y2<.1 Million MWh Y1 .1 Million to .4 Million MWh Y1 .4 Million to 1 Million MWh Y2>1 Million MWh Mean 0.268907 0.881783 3.798734 6.53528 Median 0.210769 0.623804 4.941761 3.362355 Maximum 0.703572 2.302246 6.224189 21.11706 Minimum 0.025861 0.084326 0.542396 1.970902 Observations 9 6 5 6 Table A.6 PK Total Cost PK < 4.5% PK 4.5% to 5.5% PK 5.5% To 7% Pk >7% Mean 0.708349 2.112953 1.031069 7.421714 Median 0.266407 1.20803 0.639817 6.111719 Maximum 3.136269 6.859969 2.302246 21.11706 Minimum 0.025861 0.210769 0.542396 0.067158 Ob servations 8 9 4 5
84 Table A.7 PP Total Cost PP < 28 $/MWh PP 28 32 $/MWh PP 32 40 $/MWh PP >40 $/MWh Mean 1.126968 0.947862 1.338856 7.386727 Median 0.476617 0.452389 1.190816 6.167954 Maximum 3.136269 4.941761 2.302246 21.11706 Minimum 0.06611 0.025861 0.671547 0.418983 Observations 6 10 4 6 Table A.8 Customers Total Cost Customers <10,000 Customers 10,000 40,000 Customers 40,000 160,000 Customers >160,000 Mean 0.141073 0.487069 2.130377 8.065162 Median 0.066634 0.452389 2.136574 6.167954 Maximum 0.542396 0.703572 3.588441 21.11706 Minimum 0.025861 0.210769 1.173602 3.136269 Observations 6 8 6 6 Table A.9 Hydro Total Cost Hydro <75% Hydro 75% 90% Hydro >90% Mean 8.939746 1.097169 2.602046 Median 5.52674 0.452389 1.502909 Maximum 21 .11706 6.224189 6.859969 Minimum 3.588441 0.025861 0.542396 Observations 4 18 4 Table A. 10 BPA Total Cost BPA <60% BPA 60% 90% BPA >90% Mean 5.470556 2.647015 0.329333 Median 3.063739 1.970902 0.210769 Maximum 21.11706 6.224189 1.20803 Minimum 0.54 2396 0.410838 0.025861 Observations 8 7 11
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