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The economic and policy aspects of small hydro development in British Columbia 1990

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T H E ECONOMIC AND P O L I C Y A S P E C T S OF S M A L L HYDRO DEVELOPMENT I N B R I T I S H COLUMBIA b y G E O F F R E Y EDWARD GEORGE C R O L L B . A . S c . , T h e U n i v e r s i t y o f B r i t i s h C o l u m b i a , 1986 A T H E S I S SUBMITTED I N P A R T I A L F U L F I L L M E N T OF THE REQUIREMENTS FOR THE DEGREE OF MASTER OF A P P L I E D S C I E N C E i n THE F A C U L T Y OF GRADUATE S T U D I E S ( D e p a r t m e n t o f C i v i l E n g i n e e r i n g ) We a c c e p t t h i s t h e s i s a s c o n f o r m i n g t o t h e r e q u i r e d s t a n d a r d s T H E U N I V E R S I T Y OF B R I T I S H COLUMBIA S e p t e m b e r , 1990 © G e o f f r e y E d w a r d G e o r g e C r o l l , 1990 In presenting this thesis in partial fulfilment of the requirements for an advanced degree at the University of British Columbia, I agree that the Library shall make it freely available for reference and study. I further agree that permission for extensive copying of this thesis for scholarly purposes may be granted by the head of my department or by his or her representatives. It is understood that copying or publication of this thesis for financial gain shall not be allowed without my written permission. Department of C i v i l Engineering The University of British Columbia Vancouver, Canada Date October 6, 1990 DE-6 (2/88) ABSTRACT Small hydrppower of f e r s many advantages as a source of energy and i t has been successfully developed by the private sector i n the U.S. and in Ontario. Although there i s considerable i n t e r e s t i n developing B r i t i s h Columbia's vast small hydro resource, there has been very l i t t l e progress to date. The reasons for t h i s are related more to economic and p o l i t i c a l factors than to technical issues. In t h i s thesis I review the s i t u a t i o n i n B.C. and propose a p o l i c y framework for energy purchase price, one of the main issues involved i n small hydro development. The price offered small hydro producers for t h e i r e l e c t r i c i t y i s c l e a r l y l e s s than B.C. Hydro's avoided cost, but there i s l i t t l e evidence to support the amount offered. I suggest that, i n the absence of an established, competitve market, energy purchase rates should be based on the u t i l i t y ' s avoided costs, and that avoided costs be determined by amortizing the c a p i t a l costs of the next scheduled project over a 20 year period, rather than basing them on the average l e v e l i z e d costs of a l l future projects. Furthermore, small hydro development should take a two-stage approach, s i m i l a r to Ontario's, whereby energy i s i n i t i a l l y purchased at the u t i l i t y ' s f u l l avoided cost and l a t e r , when the small hydro industry has had a chance to develop, energy would be purchased at market value or through a competitive bidding process. i i TABLE OF CONTENTS ABSTRACT i i LIST OF TABLES V LIST OF FIGURES v i ACKNOWLEDGEMENTS v i i CHAPTER 1 : INTRODUCTION 1 CHAPTER 2 : BACKGROUND ON SMALL HYDRO DEVELOPMENT 4 2.1 : D e f i n i t i o n of Small Hydro 4 2.2 : Virtues of Small Hydro 4 2.3 : American Experience 8 2.3.1 : Public U t i l i t i e s Regulatory P o l i c i e s Act .. 8 2.3.2 : Independent Power Industry 11 2.3.3 : Washington State 12 2.4 : Canadian Experience 14 2.4.1 : Canadian Hydroelectric Industry 14 2.4.2 : Ontario Independent Power Program 16 2.4.3 : Alberta Small Power Program 22 2.4.3.1 : Small Power Inquiry 22 2.4.3.2 : Small Power Development Program 25 CHAPTER 3 : SITUATION IN B.C 27 3.1 : Government P o l i c i e s 27 3.2 : B.C. Hydro's P o l i c i e s 28 3.3 : Progress to Date 32 CHAPTER 4 : PRICING HYDROELECTRIC ENERGY 35 4.1 : General P r i n c i p l e s of Energy P r i c i n g 35 4.2 : B.C. Hydro's Energy Costs 3 8 4.3 : Avoided Costs 44 4.3.1 : Avoided Costs of S i t e C 46 4.3.2 : Different Accounting for S i t e C Costs 48 4.4 : Suggested Avoided Cost P r o f i l e 56 4.5 : Comparison with B.C. Hydro's Offer 58 CHAPTER 5 : VALUE OF SMALL HYDRO POWER 63 5.1 : Discussion of B.C. Hydro's Purchase Rate 63 5.2 : Firm Capacity of Small Hydro 65 5.3 : Risk and R e l i a b i l i t y 70 5.4 : Windfall P r o f i t s 72 i i i C H A P T E R 6 : ENERGY P R I C I N G P O L I C Y FOR S M A L L HYDRO 7 5 6 . 1 : S u g g e s t e d P o l i c y 75 6 . 1 . 1 : F i r s t S t a g e 75 6 . 1 . 2 : S e c o n d S t a g e 78 6 .2 : P o l i c y R a t i o n a l e 79 CHAPTER 7 : SUMMARY AND CONCLUSIONS 85 7 . 1 : C o n c l u s i o n s 85 7 . 2 : S u g g e s t i o n s f o r F u r t h e r R e s e a r c h 86 R E F E R E N C E S 89 A P P E N D I X 1 : B a c k g r o u n d on PURPA 92 A P P E N D I X 2 : O n t a r i o H y d r o ' s S m a l l P o w e r P u r c h a s e R a t e s . . 95 A P P E N D I X 3 : A l b e r t a S m a l l Power I n q u i r y 97 A P P E N D I X 4 : B . C . H y d r o ' s I P P E n e r g y P u r c h a s e P o l i c y 102 A P P E N D I X 5 : E n e r g y C o s t s o f S i t e C 100 A P P E N D I X 6 : P r i c e A d j u s t m e n t f o r F i r m E n e r g y 109 i v L I S T OF T A B L E S T A B L E 1 : H y d r o p o w e r C a p a c i t i e s 5 T A B L E 2 : H y d r o p o w e r A d d i t i o n s i n U . S . U n d e r PURPA 10 T A B L E 3 : B . C . H y d r o ' s V a l u e o f E n e r g y 40 T A B L E 4 : S i t e C P r o j e c t S p e c i f i c a t i o n s a n d C o s t s 47 T A B L E 5 : E n e r g y P r i c i n g R a t e s 1 9 8 9 - 1 9 9 9 62 T A B L E 6 : C o m p a r i s o n o f E n e r g y P u r c h a s e R a t e s 64 v L I S T OF F I G U R E S F I G U R E 4 . 1 : B . C . H y d r o ' s M a r g i n a l V a l u e o f E n e r g y 41 F I G U R E 4 . 2 : S i t e C P r o j e c t C a s h F l o w s 49 F I G U R E 4 . 3 : S i t e C L e v e l i z e d C a s h F l o w s 50 F I G U R E 4 . 4 : S i t e C C a s h F l o w s - 70 Y e a r D e p r e c i a t i o n . 52 F I G U R E 4 . 5 : S i t e C C a s h F l o w s - 20 Y e a r D e p r e c i a t i o n . . . . 53 F I G U R E 4 . 6 : D i f f e r e n t A c c o u n t i n g C o s t s f o r S i t e C 55 F I G U R E 4 . 7 : A v o i d e d C o s t P r o f i l e s ( 1 9 9 2 - 2 0 2 1 ) 57 F I G U R E 4 . 8 : 20 Y e a r P u r c h a s e R a t e s S t a r t i n g i n 1992 59 v i ACKNOWLE DGEMENTS I w o u l d l i k e t o t h a n k D r . S . O . ( D e n i s ) R u s s e l l f o r h i s g u i d a n c e , e n c o u r a g e m e n t , a n d i n s p i r a t i o n . I am g r a t e f u l t o G l e n M c D o n n e l l o f S i g m a E n g i n e e r i n g L t d . f o r h i s h e l p a n d i d e a s a n d R o g e r B r y e n t o n , f o r m e r l y o f E n e r g y , M i n e s a n d R e s o u r c e s C a n a d a , f o r h i s a s s i s t a n c e a n d i n f o r m a t i o n . I w o u l d a l s o l i k e t o t h a n k D r . W . F . C a s e l t o n a n d D r . P e t e r Nemetz o f t h e Commerce F a c u l t y f o r t h e i r v a l u a b l e i n p u t a n d D r . A l a n R u s s e l l f o r h i s e n c o u r a g e m e n t . I am g r a t e f u l t o D r . P e t e r L u s z t i g , D a v i d D e v i n e , a n d t h e M . B . A . O f f i c e f o r t h e i r a s s i s t a n c e i n p e r m i t t i n g me a c c e s s t o t h e M . B . A . p r o g r a m . I w o u l d a l s o l i k e t o t h a n k B . C . H y d r o p e r s o n n e l f o r t h e i r h e l p a n d i n f o r m a t i o n . T h a n k s t o my f a m i l y a n d f r i e n d s f o r t h e i r n e v e r - e n d i n g e n c o u r a g e m e n t , s u p p o r t a n d i n t e r e s t i n my w o r k . I am g r a t e f u l f o r t h e f i n a n c i a l s u p p o r t o f t h e N a t u r a l S c i e n c e s R e s e a r c h C o u n c i l , t h e D e l t a West G r o u p , a n d C r o l T e c h R e s o u r c e D e v e l o p m e n t . M o s t o f a l l I w o u l d l i k e t o t h a n k my b e a u t i f u l w i f e , S u s a n , f o r h e r s t e a d f a s t l o v e , s u p p o r t , a n d p a t i e n c e . T h a n k s f o r s h a r i n g my v i s i o n a n d g o a l s a n d h e l p i n g me make t h e m a r e a l i t y . v i i CHAPTER 1 : INTRODUCTION I began my graduate research with two concepts i n mind. The f i r s t was that engineers should be prepared to f i n d solutions to economic, p o l i t i c a l , and s o c i a l problems as w e l l as t e c h n i c a l ones, i n order that projects b e n e f i t i n g society continue to be b u i l t . Engineers should be w i l l i n g to take a leadership r o l e i n a l l phases of an engineered f a c i l i t y : conception, design, financing, government approval and regulation, construction, and operation. The second was that small h y d r o e l e c t r i c generating plants were projects that had (1) many economic, environmental, and s o c i a l benefits; and (2) a s i g n i f i c a n t p o t e n t i a l for development i n B r i t i s h Columbia. Private sector development of small hydropower generation provides a good vehicle for exploring the economic, p o l i t i c a l , and t e c h n i c a l factors involved i n the multiple phases of an engineering project. These two concepts formed the basis of my research into private small hydro development i n B.C. Small scale hydroelectric power production by the private sector i s not a new idea. In fact, the Canadian e l e c t r i c a l industry got i t s s t a r t around the turn of the century with the construction of i n d i v i d u a l small hydro generating plants serving l o c a l needs. Later they were consolidated, and many were abandoned, as larger u t i l i t i e s , most of them p r o v i n c i a l , assumed control of power d i s t r i b u t i o n and began building larger scale projects. However, small hydro i s making a comeback. Af t e r varying degrees of success i n the U.S. and i n 1 Ontario, there i s now considerable i n t e r e s t i n having B r i t i s h Columbia's vast small hydro resources developed by the private sector. For some i t has been a long wait, f o r others i t i s a new opportunity. Yet there has been l i t t l e development action to date. The hold-up can be attributed to economic and p o l i t i c a l factors rather than technical issues. These types of problems, s i m i l a r to many of those faced by engineers and managers, are often more d i f f i c u l t to resolve than the tec h n i c a l ones. In t h i s thesis I review what i s happening i n small hydro development i n B.C. and propose a p o l i c y framework for s e t t i n g energy purchase prices, one of the main issues involved i n small hydro development. The p r i c e being offered for small hydro power i s well below B.C. Hydro's cost of new e l e c t r i c a l generation, making small hydro projects that should be f e a s i b l e , uneconomic. This has been one of the primary b a r r i e r s to development i n B.C. Although many of the issues discussed herein are usually more associated with economics or commerce based research, the s i g n i f i c a n c e of t h i s thesis i n a c i v i l engineering context l i e s i n the f a c t that many of the problems faced by c i v i l engineers are not l i m i t e d to technical issues, and that the economic and p o l i c y issues of small hydro development i n B.C. must be solved f i r s t before any s i g n i f i c a n t " t r a d i t i o n a l " c i v i l engineering work can be performed. At the same time the 2 concepts and techniques u t i l i z e d a l l f a l l within the domain of engineering economics. This t h e s i s takes the following form: Chapter 2 reviews the progress made with small hydro development i n other parts of North America. Special attention i s given to Washington State because of i t s proximity to B.C. and to Ontario and Alberta as these are the only other Canadian provinces with progressive p o l i c i e s i n place. Chapter 3 reviews the present s i t u a t i o n i n B.C. and the p o l i c i e s of B.C. Hydro. Chapter 4 discusses the value of energy and the concept of avoided cost and suggests a method for determining a u t i l i t y ' s avoided costs. Chapter 5 examines i n d e t a i l the value of small hydro power and B.C. Hydro's purchase p r i c e p o l i c y . Chapter 6 proposes a new p o l i c y to set energy purchase p r i c e s . Chapter 7 summarizes my conclusions and suggests a number of areas for further research into small hydro development. 3 CHAPTER 2 : BACKGROUND ON SMALL HYDRO DEVELOPMENT 2.1 : D e f i n i t i o n of Small Hydro By "small hydro", I am usually r e f e r r i n g to a hydroelectric plant with less than 5 megawatts (MW) of capacity. Although small hydro often includes c a p a c i t i e s up to 20 MW, B.C. Hydro has made a d i s t i n c t i o n between over 5 and under 5 MW projects based on various t e c h n i c a l , regulatory, and administrative concerns. To give an idea of the scale of 5 MW, B.C. Hydro's next planned hydro project, S i t e C on the Peace River, w i l l have 900 MW of capacity and B.C.'s t o t a l generating capacity i s over 10,000 MW. A 5 MW plant, for example, can serve over 1,000 homes. Other examples of power demands and capacity are given i n Table 1. 2.2 : Virtues of Small Hydro Looking at energy i n global terms, there are obvious advantages to hydropower as a source of energy. I t i s a renewable resource, which i s important i n a world heavily dependent f o r i t s energy on non-renewable, depleting fuels such as o i l , gas, and coal. Although some projects may have adverse environmental impacts, hydropower i s non-polluting and does not contribute to the greenhouse e f f e c t with a l l i t s unforeseeable side e f f e c t s . Small hydro also o f f e r s advantages over larger scale hydroelectric projects. 4 TABLE 1 : Hydropower Capacities D e f i n i t i o n According to Capacity: Micro Hydro 1 kW - 100 kw Small Hydro 100 kW - 20 MW Medium and Large > 20 MW Hydroelectric Plants Power Demands: Typical Home 1 kW - 20 kW Community approx. 3 kW/home Farm, Small Business 10 kW - 50 kW Industry 50 kW - 50 MW Capacity: S i t e C Project (not b u i l t ) 900 MW G.M. Shrum (B.C.'s largest) 2,416 MW B.C. - firm hydro capacity (1989) 9,500 MW - t o t a l capacity 10,500 MW Canada - i n s t a l l e d hydro capacity (1989) 57,900 MW - t o t a l capacity 97,000 MW Source: Ontario Ministry of Energy (1986) f B.C. Hydro (1989), and Hocker (1989). Although a large plant can usually generate e l e c t r i c a l energy more economically than a small one, the economics of a hydro plant are very dependent on s i t e conditions and, i n the ri g h t circumstances, a small plant can be as economical or more so than larger ones. The r e l a t i v e cost of constructing large scale hydro f a c i l i t i e s i n B.C. has r i s e n as many of the low cost, environmentally acceptable s i t e s have already been developed (Sigma and Robinson, 1983, p.1-1). In contrast, the po t e n t i a l of small hydropower has la r g e l y been ignored and many of the r e l a t i v e l y low cost s i t e s are undeveloped. As a r e s u l t , the cost advantage of large scale hydro development has decreased r e l a t i v e to small hydro power i n recent years. 5 Small plants can be brought on l i n e quickly and add capacity i n small manageable increments, thus helping to keep the supply and demand for energy i n balance. In contrast, large plants have long lead times and they provide large incremental additions to the capacity of t h e i r system, which can take time to absorb, and which often leads to a jump i n e l e c t r i c i t y rates. Small plants spread the economic benefits from constructing and operating generating plants over a wider range of time and geographical area. I t has been shown that many small hydro plants can make a larger contribution to the province's economy than a few large ones (Schaffer, 1987, p.41). A large number of small hydro plants can also enhance the d i v e r s i t y of the e l e c t r i c a l generation and transmission system. F i n a l l y , small hydro plants generally have much lower environmental impacts than large plants. Small hydro i s not without disadvantages, which include lack of energy storage, questionable "firm" capacity and r e l i a b i l i t y , lack of economies of scale, and greater s u s c e p t i b i l i t y to damage from floods, sediment, and debris than la r g e r plants. Small hydro plants lend themselves well to private ownership, which i s i n l i n e with world-wide trends towards the p r i v a t i z a t i o n of services and f a c i l i t i e s previously provided by governments or other large agencies. Development and 6 ownership of small hydro plants by independent power producers allows for management on a scale more appropriate to the scale of the f a c i l i t i e s than does ownership by government agencies or large u t i l i t i e s . B.C. Hydro has not expressed i n t e r e s t i n developing small hydro themselves and t h i s may be due to an i n a b i l i t y to develop small s i t e s c o s t - e f f e c t i v e l y because of high overhead and an organizational structure more appropriate for large projects. Private development of small hydro plants also encourages l o c a l enterprise and l o c a l job creation, a goal of almost a l l governments. Most of the equipment and expertise required for small hydro design and construction can be found i n B.C., thereby adding - to the province's economic base. Major equipment for large hydro and thermal plants, on the other hand, often needs to be purchased outside the province or overseas. Independent power producers provide healthy competition f o r the provision of e l e c t r i c i t y , leading to a long term reduction of costs, and can add capacity to the province's system without increasing B.C. Hydro's debt. Thus, i t i s easy to make the case that, wherever they are l i k e l y to be economical, the development of small hydro plants should be encouraged, and that they would be best developed, owned and operated by private developers, or Independent Power Producers (IPPs). However, there are a number of problems to be solved before a s i g n i f i c a n t number of p r i v a t e l y developed small hydro plants can become a r e a l i t y . They revolve around 7 questions such as: "How should t h i s resource be developed, keeping i n mind the interests of the public, the developer, and other resource users including the environment?", "Who should get the opportunity to develop which s i t e s ? " , and "How can a f a i r rate of payment be established for the energy produced?" Before examining these problems further, a b r i e f d e s c r i p t i o n of the experience i n the U.S., Ontario, and Alberta may provide some insights. 2.3 : The American Experience 2.3.1 : The Public U t i l i t i e s Regulatory P o l i c i e s Act (PURPA) The North American small hydro resurgence got i t s s t a r t i n the U.S. with the passage of the Public U t i l i t i e s Regulatory P o l i c i e s Act (PURPA) i n 1979. PURPA was a component of a larger package of l e g i s l a t i o n , the National Energy Act of 1978. Spawned by the energy c r i s i s of the 1970's, PURPA started a new d i r e c t i o n i n how energy resources i n the U.S. would be developed over the following decade. The o v e r a l l intent of PURPA was to foster development of e f f i c i e n t domestic sources of energy, including cogeneration and renewable resources such as hydro, wind, and solar, and to reduce dependence on foreign energy sources, most notably f o s s i l f u e l s . PURPA mandated a guaranteed market for non- u t i l i t y generated power and provided an a t t r a c t i v e market opportunity f o r entrepreneurs to enter the f i e l d of e l e c t r i c a l power production. Established u t i l i t i e s were generally 8 opposed to the requirements to accommodate and buy power from small power producers, and t h i s led to some extensive l e g a l b a t t l e s before PURPA f i n a l l y prevailed. Background on PURPA and the ensuing court cases i s given i n more d e t a i l i n Appendix 1. The Federal Energy Regulatory Commission (FERC), which was responsible for implementing and overseeing PURPA, established a standard for power purchases at f u l l avoided cost. Avoided cost was defined as "the incremental cost to a u t i l i t y of e l e c t r i c a l energy which, but for the purchase from a q u a l i f y i n g f a c i l i t y , the u t i l i t y would generate i t s e l f or purchase from another source" (WSEO, 1989, p.II-1). Individual states were given the power to e s t a b l i s h t h e i r own rules, including how to determine avoided cost. Many states adopted the f u l l avoided cost standard while others, such as New York, set a higher rate to promote development. Although the expectations of PURPA were not quite clear, a 1980 report prepared for FERC predicted a t o t a l of about 12,000 MW of capacity to be provided by cogeneration and small power production under PURPA by 1995, 3500 MW of which would be from small hydro (Eden, 1985, p.582). The 12,000 MW target of t o t a l new capacity added under PURPA was exceeded i n 1989 and by the end of the year, 519 hydro projects had come on l i n e , representing 3,140 MW of capacity (Marier, Nov. 1989, Jan. 1990). Table 2 shows hydro project additions under PURPA from 1980 to 1989. 9 TABLE 2 : Hydropower Proi ect Additions Under PURPA YEAR HYDRO PROJECTS ON-LINE No. Capacity (MW) 1980 8 251 1981 32 255 1981 32 275 1983 73 567 1984 81 486 1985 31 43 1986 111 296 1987 90 210 1988 30 419 1989 31 337 TOTAL 519 3 , 139 Source: Marier (Jan. 89, Nov . 89, Jan. 90) This i s quite an accomplishment considering the early resistance to the l e g i s l a t i o n . However, given the current energy surplus, a corresponding drop i n avoided costs (largely due to low o i l prices) , the loss i n 1986 of some s i g n i f i c a n t tax incentives for some sources of power (including hydro), and increasing environmental opposition to hydro development, growth has slowed and the industry has consolidated. As well, FERC has been modifying i t s rules, relaxing the avoided cost standard, and proposing the use of competitive bidding to est a b l i s h market value for power purchases from IPPs. While many u t i l i t i e s f e e l that PURPA was a costly experiment which l e f t them with long term contracts at rates above t h e i r present avoided cost, many others, e s p e c i a l l y 10 those i n the private power industry, believe PURPA was very successful i n paving the way for the development of small, private power production. According to the Washington State Energy O f f i c e , "...nationwide, PURPA has been extremely successful i n stimulating the emergence of a m u l t i - b i l l i o n d o l l a r independent power producing industry..." (WSEO, 1989, p.1-2) . 2.3.2 : Independent Power Industry Donald Marier, a long-time industry observer, states "...the growth of the independent energy industry i s t r u l y a success story which shows the value of competition i n the power generation market" (Marier, 1990, p.2). Total independent power production capacity, which includes q u a l i f y i n g f a c i l i t i e s (QFs) as well as independent power producers not covered by PURPA, i s more d i f f i c u l t to quantify. A survey by the National Association of Regulatory U t i l i t y Commissioner's (NARUC) showed 17,189 MW of e x i s t i n g capacity as of June 1987 (Brown, 1989, p.22). According to a study by the Edison E l e c t r i c I n s t i t u t e (EEI) which attempted to include most of the pre-PURPA capacity s t i l l operating as well as post-PURPA projects, the capacity of n o n - u t i l i t y sources of energy was 25,323 MW as of December 1986, about 4% of t o t a l U.S. capacity (Brown, 1989, p.22). In C a l i f o r n i a , f o r example, there was enough i n s t a l l e d and under-construction capacity to boost the output of independent power producers to 11 2 5 percent of the state's t o t a l generating capacity (WSEO, 1989, p.1-2). Independent producers w i l l continue to be a dominant force i n bu i l d i n g new capacity over the next ten years. I t i s expected that i n 1990, for the f i r s t time, the independent energy industry w i l l bring on-line new capacity equal to that brought on by u t i l i t i e s (Marier, 1990, p.10). FERC estimates that 50% of capacity additions i n the U.S. between now and 1997 w i l l be from non-traditional generation (OMOE, 1989, p. 2). The NARUC and EEI studies indicate that as high as 3 0 to 40% of new generating capacity i n the U.S. w i l l be b u i l t by independents over the next decade (Brown, 1989, p.22). The U.S. Department of Energy (DOE) i s projecting that n o n - u t i l i t y generation w i l l grow at t r i p l e the rate of u t i l i t y generation through the 1990's with independents adding 3 0,000 MW of new generating capacity from 1989 u n t i l the year 2000 (Marier, Jan. 1989, p.2). The Energy Information Administration (EIA) projects n o n - u t i l i t y capacity to increase to 57,300 MW by the year 2000, or 7.4% of t o t a l U.S. capacity. Thus, IPPs are and w i l l continue to be a s i g n i f i c a n t source of e l e c t r i c a l energy i n the U.S. 2.3.3 : Washington State Washington State, B.C.'s neighbour to the south, has more developed hydroelectric capacity than any other state i n the U.S. and s t i l l has s i g n i f i c a n t p o t e n t i a l remaining. Over 170 12 MW of QF generating capacity has come on-line i n Washington since the passage of PURPA, including 20 small hydro projects with a combined capacity of 77 MW (WSEO, 1989, p.1-3). The State does not set avoided costs f o r i t s u t i l i t i e s but d i r e c t s them to estimate t h e i r avoided cost and to adjust that i n response to the apparent market p r i c e f o r power. U t i l i t i e s are required to send out requests f o r proposals for new sources of power at least every two years. The proposals are evaluated on a number of bases, including price, environmental impacts, f i n a n c i a l i n t e g r i t y , and f u e l supply. Power purchase rates are negotiated between the u t i l i t i e s and the independent producers. Prices may vary according to many factors including firm energy production, load following c a p a b i l i t y , performance guarantees, project s t a r t date, length of contract, and front-loading or l e v e l i z a t i o n provisions. Power purchase contracts are thus t a i l o r e d to s p e c i f i c project c h a r a c t e r i s t i c s . State l e g i s l a t i o n also streamlines and s i m p l i f i e s the permitting process and provides f i n a n c i a l incentives f o r renewable resources. For example, owners of ce r t a i n power projects are allowed to pay a reduced business tax and are exempt from property taxation for seven years. A f t e r the passage of PURPA, avoided cost projections were i n i t i a l l y high because of the predic t i o n of an e l e c t r i c a l supply d e f i c i t . In Washington, a hydropower "gold rush" ensued. By mid-1982, developers had f i l e d f or over 250 hydro 13 projects. Speculators f i l e d dozens of permit applications to secure r i g h t s on p o t e n t i a l l y a t t r a c t i v e s i t e s . When the e l e c t r i c i t y d e f i c i t became a surplus, avoided costs dropped as did i n t e r e s t i n the development of hydropower and other renewable resources. In contrast, avoided costs and purchase contract terms i n C a l i f o r n i a were set by the Public U t i l i t i e s Commission (PUC) and based on high baseline and escalation rates f o r o i l and natural gas. Under the PUC's "standard o f f e r " system, C a l i f o r n i a u t i l i t i e s were forced to sign contracts with unexpected and unprecedented numbers of QFs. Due to lags i n regulatory response and the decline i n o i l p r i c e s , C a l i f o r n i a u t i l i t i e s now pay much more for QF e l e c t r i c i t y than i t costs them to generate at t h e i r own thermal plants. 2.4 : Canadian Experience 2.4.1 : Canadian Hydroelectric Industry Hydroelectric power i s a very important source of energy for Canada, e s p e c i a l l y i n B.C. Currently, Canada has about 57,000 MW of hydroelectric generating capacity, representing 60% of i t s approximately 97,000 MW of t o t a l capacity (Hocker, 1989). Although the U.S. has more hydro capacity (85,000 MW representing 13% of the nation's t o t a l capacity), Canada ac t u a l l y generates more hydroelectric energy (Eden, 1989, and H a l l , 1988) . In fact, i n the 1980's, Canada became the leading producer of hydroelectric power i n the world. More 14 than 90% of Canada's power supply i s provided by eight p r o v i n c i a l government-owned u t i l i t i e s and one investor-owned u t i l i t y . Ontario i s the largest producer of e l e c t r i c i t y with 29,600 MW of t o t a l capacity (6,500 MW of which i s hydro), followed by Quebec with 25,000 MW of t o t a l capacity (23,800 MW of hydro). B r i t i s h Columbia has 9,300 MW of hydroelectric capacity out of 10,500 MW of t o t a l capacity. Although hydro projects range i n s i z e from less than 1 MW to 2,400 MW, 99% of B.C. Hydro's hydro capacity comes from plants larger than 2 0 MW. In contrast, hydropower accounts for less than 20% of Alberta's 6,200 MW of capacity. Before the 1980's, p r i v a t e l y produced power was not a s i g n i f i c a n t factor i n Canada. However, the climate for private power projects i s rapidly changing. Although i n the past they did very l i t t l e to encourage private generators, some u t i l i t i e s and p r o v i n c i a l governments have recently adopted the view that private power has a larger r o l e to play i n providing a diverse and f l e x i b l e source of e l e c t r i c i t y . Ontario has the most advanced and comprehensive p o l i c y to date, but both B.C. and Alberta are a c t i v e l y involved i n promoting independent power production. I w i l l f i r s t examine the s i t u a t i o n s i n Ontario and Alberta i n d e t a i l , and leave a discussion of B.C.'s p o l i c i e s to a l a t e r chapter. 15 2.4.2 : Ontario Independent Power Program The Ontario Government's Ministry of Energy (OMOE) has been a strong supporter of independent power generation (also referred to as P a r a l l e l Generation and Non - U t i l i t y Generation) and Ontario Hydro, the p r o v i n c i a l u t i l i t y , has been cooperative to a degree. In 1989, the OMOE issued a new po l i c y on p a r a l l e l generation that c l e a r l y sets out i t s p o l i c i e s , goals, and rationale. Although Ontario Hydro i s not bound to adopt any or a l l of the p o l i c y recommendations, they appear l i k e l y to incorporate many key elements of the pol i c y . The h i g h l i g h t s of t h i s p o licy and some of the related issues are discussed below. Purchase rates, the government has stated, should f u l l y r e f l e c t the value of the power to the e l e c t r i c a l system and therefore should be based on avoided cost, which i s defined as the cost that would otherwise be incurred by Ontario Hydro by generating the power i t s e l f or purchasing from other u t i l i t i e s . The ca l c u l a t i o n of avoided costs should take into account short and long term costs of power generation, transmission, d i s t r i b u t i o n , and purchases; environmental costs; and s o c i a l costs, where measurable. Ontario Hydro calculates i t s avoided costs based on system marginal costs and these are currently just below the average cost of power, which i s based on h i s t o r i c a l accounting costs. E l e c t r i c consumers should continue to receive r e l i a b l e e l e c t r i c i t y at reasonable rates; the development of p a r a l l e l 16 generation should not increase costs to ratepayers i n the short term and should reduce energy costs i n the long term. Ontario Hydro's methods for c a l c u l a t i n g avoided costs w i l l be subject to public review and the r e s u l t s w i l l be used to e s t a b l i s h a schedule of purchase rates f o r a l l private generators, allowing for start-up year, contract duration, and capacity factor of the generator. Although Ontario Hydro has agreed to the review, industry representatives have c r i t i c i z e d Hydro's implementation of the review process. Ontario Hydro has included the public review of avoided cost with the review of the Preferred Plan, t h e i r strategy for e l e c t r i c a l generation for the next 15 years. However, they have already delayed the t a b l i n g of the Plan several times and the review of the plan i t s e l f may take 12 to 18 months. By delaying the avoided cost review, and thereby the purchase rate schedule, some p a r a l l e l generators believe Ontario Hydro i s attempting to "stymie the development of the independent power industry" (IPPSO, Sept. 1989, p.7). A l l p a r a l l e l generators should have access to e l e c t r i c i t y purchase rates on the same basis, regardless of energy source or technology. This includes making front-end loaded rates and loan incentives from Ontario Hydro a v a i l a b l e to a l l pot e n t i a l generators. Front-end loaded rates allow faster recovery of c a p i t a l costs and are currently a v a i l a b l e only to renewable resource projects. 17 P a r a l l e l generation industry representatives have argued that the industry i n Ontario i s not yet s u f f i c i e n t l y established to support competitive bidding and that the cost of preparing a winning bid would discourage p o t e n t i a l developers. Without a developed industry, bidding may r e s u l t i n minimal benefits to ratepayers. They suggest delaying competitive bidding u n t i l the industry i s established, competitive, and i t s potential known. In support of t h i s p o s i t i o n , the government recommends a process that encourages the development of the industry i n the short term, at no added cost to the ratepayer, to ensure that they may benefit from a bidding process i n the longer term. For projects with capacity greater than 5 MW, the government proposes a two-stage s o l i c i t a t i o n process. In the f i r s t stage, a l l proposals, up to a capacity cap, meeting techn i c a l requirements would receive Hydro's avoided costs. I f the o f f e r was over-subscribed, bids would be chosen on a first-come, f i r s t - s e r v e basis. A l t e r n a t i v e l y , the projects could be selected on the basis of c r i t e r i a such as a v a i l a b i l i t y , r e l i a b i l i t y , and benefits to the system, although such a selection system could be seen as a r b i t r a r y . Through t h i s process, Ontario Hydro should be able to s o l i c i t 1000 MW of development by 1995. In the second stage, a further 1000 MW of p a r a l l e l generation could be s o l i c i t e d for development by the year 2000, depending on load growth and the r e s u l t s of the f i r s t s o l i c i t a t i o n , based on a competitive 18 bidding process. Presently, for projects over 5 MW, the u t i l i t y holds a formal Request for Proposals (RFP) process, which s o l i c i t s an unlimited amount of capacity. Purchase rates are negotiated for each project with a c e i l i n g at the avoided cost. Projects with capacity of 5 MW or l e s s would continue to be welcome at any time and exempted from the s o l i c i t a t i o n process because they can be integrated into the system r e l a t i v e l y e a s i l y . For these smaller projects a purchase rate schedule with standard rates would apply. Ontario Hydro presently has a standard rate structure for generators of 5 MW or l e s s and these projects are integrated into the system on an on-going basis. The purchase p r i c e depends on the capacity f a c t o r and increases with the rate of i n f l a t i o n . Lower rates fo r lower capacity r e f l e c t that the lower purchase rate does not include a capacity component, j u s t energy costs. In May 1989, the standard base rate was set at 3.97 cents/kWh fo r a capacity factor (CF) of 65% or greater, and escalated each year at the Ontario Consumer Price Index (CPI) f o r up to 10 years from the in-service date (see Section 5.2 fo r a d e f i n i t i o n of capacity f a c t o r ) . Thereafter, the base rate i s renegotiated. This rate i s equal to 85% of Hydro's accounting costs for power (costs incurred by Hydro to generate, transmit, and d i s t r i b u t e e l e c t r i c i t y using e x i s t i n g f a c i l i t i e s ) which i s higher than the current avoided cost for power. When avoided costs exceed 85% of the accounting costs 19 of power (projected for 1991), rates w i l l be based on avoided costs. A lower rate of 2.54 cents/kWh, based on Hydro's short term incremental energy cost, i s paid for energy from projects with a CF l e s s than 65%. Besides the standard rate, there are three other rate options for power purchases. The rate schedule i s described i n d e t a i l i n Appendix 2. One of the options offers a fixed 10-year rate for renewable resource projects, including hydro, solar, wind, and wood waste. These projects receive 4.94 cents/kWh fo r a 10- year period from the start-up date for a CF of 65% or greater. This rate i s designed to encourage, and f i n a n c i a l l y a s s i s t , development of n o n - u t i l i t y generation from renewable resources by front-loading the forecasted standard rates over the 10- year period. This reduces the r i s k s to private generators by allowing f a s t e r recovery of investment. This rate i s l i m i t e d to energy from renewable resources because these projects are expected to have long l i v e s and be r e l a t i v e l y i n s e n s i t i v e to changes i n market conditions. The industry has c r i t i c i z e d the purchase rate schedule because the purchase rate i s roughly equivalent to the average cost of a new u t i l i t y plant over i t s l i f e i n constant d o l l a r s , known as the l e v e l i z e d cost. This l e v e l i z e d cost i s computed on the basis of paying t h i s rate i n i t i a l l y and then escalating i t by the i n f l a t i o n rate over time. The accounting treatment of Ontario Hydro plants, on the other hand, allows a much higher recovery of the costs of the plant from rates i n the 20 early years of the plant's l i f e . A s i m i l a r treatment to private generators would reduce t h e i r r i s k s by reducing the project's payback period. I w i l l discuss t h i s problem of l e v e l i z e d cost versus accounting costs i n more d e t a i l i n Chapter 4. For hydropower development on Crown land, a p p l i c a t i o n must be made through the Ministry of Natural Resources, which releases s i t e s on the basis of competitive bidding. These projects, large and small, are exempt from Ontario Hydro's s o l i c i t a t i o n process. Instead, the successful applicant receives a standard purchase rate from Ontario Hydro. To prevent any one developer from monopolizing s i t e s , the number of Crown Land s i t e s that may be under development by any one proponent at any one time i s li m i t e d to three. However, there i s no consistent basis for awarding a s i t e , and developers can waste money and time without ever developing a project. This process i s now being reviewed and a new process should be developed by early 1990 which w i l l include techniques for evaluating costs and benefits of projects and methodology f o r comprehensive r i v e r planning. Total i n s t a l l e d private generation capacity i n Ontario was approximately 1200 MW i n 1988. From 1985 to 1989, 25.5 MW of p a r a l l e l generation capacity was added, 14.5 MW of which was hydro. In addition, 273 MW of new capacity has been committed, a l l of which should be developed i n the next two years (OMOE, 1989, p.2). The government estimates that 21 between 150 and 250 MW of hydropower capacity could be developed p r o f i t a b l y by the private sector. Out of 150 assessed s i t e s , 52, representing a capacity of 67 MW, have been i d e n t i f i e d as being economic. However, hydro a c t i v i t y has slowed considerably recently as the more economic s i t e s have already been developed and because of the uncertainties of the s i t e release process. Although the government r e a l i z e s that p r i v a t e generation presents some major uncertainties, including r e l i a b i l i t y and long term a v a i l a b i l i t y , these r i s k s are l i m i t e d by the fact that p a r a l l e l generation w i l l account for a r e l a t i v e l y small share of the system and s p e c i f i c r i s k s can be l i m i t e d further through purchase contract provisions. As a r e s u l t , the government believes the r i s k s of independent power production to the u t i l i t y and ratepayers are l i k e l y to be manageable and are outweighed by the p o t e n t i a l benefits. 2.4.3 : Alberta Small Power Program 2.4.3.1 : Small Power Inquiry Unlike other provinces, the major u t i l i t i e s i n Alberta are investor-owned. The largest, TransAlta U t i l i t i e s Corp., operates 4,300 MW of t o t a l capacity. There has been a growing i n t e r e s t i n n o n - u t i l i t y small power production i n Alberta since the early 1980's. The Small Power Producers Association of Alberta (SPPAA) and other p o t e n t i a l private power producers have lobbied the government to develop a p o l i c y f o r private 22 generation, including a l t e r n a t i v e p r i c i n g provisions and contract terms for the sale of t h e i r e l e c t r i c energy production. In 1987 the p r o v i n c i a l government c a l l e d for a public inquiry by the Public U t i l i t i e s Board (PUB) and the Energy Resources Conservation Board (ERCB). A f t e r a series of hearings, the Boards submitted a report o u t l i n i n g t h e i r findings and recommendations to the government i n February 1988. The Boards' recommendations included the following: 1) the Alberta Government should adopt a p o l i c y that would f a c i l i t a t e the production of e l e c t r i c i t y by independent producers; 2) a l l types of power producers (including utility-owned projects) with i n d i v i d u a l generating c a p a c i t i e s of 2.5 MW or less, from any power source, should be classed as small power producers (SPPs); 3) i n i t i a l l y , a maximum of 100 MW of small power capacity could be interconnected to the Alberta system without a f f e c t i n g system r e l i a b i l i t y or increasing cost to consumers; 4) the p r i c e to be paid for small power generation should be based on long-term u t i l i t y avoided costs and that price should vary according to the r e l i a b i l i t y and a v a i l a b i l i t y of the power, and the length and s t a r t i n g date of the contract; 23 5) small power generation should be reviewed a f t e r 1994, or when 100 MW i s interconnected, whichever occurs f i r s t , so that i t s value to the e l e c t r i c i t y system can be f u l l y assessed and the p r i c e s reviewed. Fixed prices based on l e v e l i z i n g the u t i l i t i e s ' avoided cost ( i . e . , taking an escalating rate and c a l c u l a t i n g an equivalent fixed rate) over the l i f e of a contract were determined for 10, 15, and 2 0-year contracts. These prices, shown i n Appendix 3, would remain fixed f o r the duration of the contract and vary depending on which year the contract begins. The Boards o r i g i n a l l y recommended that there should be separate prices for firm and as-available (secondary) power. However, they l a t e r determined that the p r i c e s should i n i t i a l l y be equal and any necessary adjustments could be made when the program i s reviewed. The report also said larger n o n - u t i l i t y power producers, with capacities greater than 2.5 MW, should continue to meet regulatory requirements and negotiate contractual terms with the u t i l i t i e s using the p r i n c i p l e s and methods outlined i n the report. These include using the avoided cost as a c e i l i n g for energy purchase p r i c e . A more complex regulatory process for larger projects i s necessary to minimize any p o t e n t i a l l y adverse technical or economic impacts. The Boards recommended against using the concept of l e v e l i z i n g avoided costs to determine front-loaded fixed prices for non-SPPs because the default of such producers represents a s i g n i f i c a n t f i n a n c i a l 24 r i s k to the consumer. Further d e t a i l s of the Boards' views and recommendations are outlined i n Appendix 3. 2.4.3.2 : Small Power Development Program In response to the report, the Alberta government announced the "Small Power Research and Development Program" in June 1988. This program was designed to help small power producers using renewable fuel sources of wind, hydro, and biomass. The program f a c i l i t a t e s small projects so that the assessment of small power generation could be c a r r i e d out i n the near term. Under the program, SPPs are able to contract with u t i l i t i e s to s e l l power from small hydro, wind or biomass projects l e s s than 2.5 MW i n capacity (except f o r a l i m i t e d number of larger p i l o t projects) at a f i x e d rate of 5.2 cents/kWh. This p o l i c y i n e f f e c t brings the p r i c e the Inquiry set for the year 1995 forward to the present with the goal of encouraging small power projects using renewable resources to come on-stream sooner. E l e c t r i c u t i l i t i e s are not e l i g i b l e for the program. These contracts are t y p i c a l l y f o r 15 or 20 year terms. In addition to the renewable energy projects supported by the program, other small power projects could be developed by 1994 at prices set out i n the report. The program began i n October 1988 and i s expected to run u n t i l 125 MW of e l i g i b l e small power projects are interconnected to the system or the end of 1994, whichever comes f i r s t . The 25 benefits and pote n t i a l contribution of small power, including deferring large generating plants, w i l l be assessed at that time. In November 1989, the government announced changes to the program to further benefit small power producers. The p r i c e paid for e l e c t r i c i t y from SPPs was increased and SPPs were given a choice between a fixed p r i c e or a p r i c e escalating with i n f l a t i o n . The program was also extended to include s o l a r and peat power generation. The increase i n the purchase p r i c e r e f l e c t s the potential environmental benefits of using renewable resources to generate e l e c t r i c i t y . The fi x e d p r i c e option guarantees SPPs 5.2 cents/kWh u n t i l 1995, and 6.0 cents/kWh thereafter. The escalating option s t a r t s at 4.64 cents/kWh i n 1990, and then escalates with i n f l a t i o n . The u t i l i t y i s required to pay these prices for 10 years, a f t e r which time the prices w i l l be set by the Public U t i l i t i e s Board. In addition, small power producers would be e l i g i b l e f o r the u t i l i t y companies' income tax rebate program. Under the tax rebate program, income tax paid by u t i l i t i e s i s rebated and passed on to power consumers. This w i l l allow small producers to receive the same income tax treatment as the large generating u t i l i t i e s . 26 CHAPTER 3 : SITUATION IN B.C 3.1 : Government P o l i c i e s B.C. Hydro's inter e s t i n encouraging IPPs i s a d i r e c t r e s u l t of p r o v i n c i a l government d i r e c t i v e s . The government has four goals i n encouraging the development of private power: - introduce more competition into the e l e c t r i c a l production industry; export of e l e c t r i c i t y by the private sector; - improve e f f i c i e n c y and reduce costs of the system; - encourage private sector investment i n power production (Swoboda, 1990). Jack Davis, B.C. Minister of Energy, Mines, and Petroleum Resources, has said that much of the growth i n B.C.'s e l e c t r i c i t y demand w i l l be met by private sector power projects instead of B.C. Hydro. While B.C. Hydro, a Crown corporation, w i l l remain the dominant player, the government intends to r e l y as much as possible on the marketplace to provide increased power generation for both the domestic and export markets (Lewis, A p r i l 5, 1990). Although these are stated goals of the r u l i n g S o c i a l Credit Party, there are some indications that the opposition New Democratic Party (NDP) would also support private power production to some extent. Mike Harcourt, leader of the NDP, recently stated that the NDP prefers smaller generation 27 projects over large ones, and export of firm e l e c t r i c i t y would be permitted only i f the sale price covered a l l long-term costs, including s o c i a l and environmental costs (Lewis, A p r i l 8, 1990). 3.2 : B.C. Hydro Policy To meet these government objectives, B.C. Hydro has announced a p o l i c y of encouraging private power development i n four separate areas: projects for non-integrated areas (those areas not connected to the main power supply g r i d ) , projects developed f o r the export market, and projects over 5 MW and projects of 5 MW or less connected to the integrated system for domestic use. For the purposes of t h i s paper, I am generally r e f e r r i n g to projects under 5 MW connected to the integrated system as t h i s i s where most of the small hydro p o t e n t i a l l i e s . For example, a 1983 study by Sigma Engineering f o r the p r o v i n c i a l government, "Small Hydropower Resource i n the Pr o v i n c i a l System," i d e n t i f i e d over 600 p o t e n t i a l small hydro s i t e s under 20 MW representing over 1400 MW of capacity. Sigma estimated that approximately 80 s i t e s generating a t o t a l of 430 MW could be developed by the private sector at or le s s than the cost of B.C. Hydro's proposed S i t e C project. Projects of 5 MW or less are also e l i g i b l e for a streamlined regulatory and administrative process, including a standard purchase rate and contract, which allows f o r a more general approach to p o l i c y evaluation. 28 B.C. Hydro defines independent power production as e l e c t r i c i t y generated by an independent or privately-owned f a c i l i t y which i s connected to the B.C. Hydro system. The u t i l i t y ' s p o l i c y statement on IPPs says i n part: In i t s e f f o r t to achieve the most economic supply of e l e c t r i c i t y , B.C. Hydro i s turning to IPP's for a portion of i t s e l e c t r i c i t y supply requirements. Cost e f f e c t i v e independent power production should allow d e f e r r a l of larger, p o t e n t i a l l y more expensive projects on the integrated system. (B.C. Hydro, May 1989, p.6) B.C. Hydro states that the benefits of independent power production include: smaller projects; defer large plants; a l l e v i a t e rate shocks; les s environmental impact; d i s t r i b u t e d economic development; competition; - enhanced government revenues; reduce losses of supplying power to non-integrated areas (Swoboda, 1990). For projects less than 5 MW, B.C. Hydro w i l l i n v i t e proposals for the supply of e l e c t r i c i t y through a Request for Proposals (RFP) process i n the spring of each year, as new generation i s , r e q u i r e d , up to a predetermined maximum t o t a l . To minimize administration and transaction costs and to f a c i l i t a t e the development of independent power projects under 29 5 MW capacity, standard conditions, including the purchase pr i c e , apply to these projects. According to B.C. Hydro, the purchase rate w i l l be set annually at a value that r e f l e c t s B.C. Hydro's incremental cost of e l e c t r i c i t y . The p r i c e i s to be announced at the time of the RFP issue and be subject to escalation. Purchase agreements w i l l be entered into on a f i r s t come, f i r s t serve basis u n t i l the aggregate capacity of the agreements i s approximately equal to the predetermined maximum t o t a l . The contract w i l l have a 20 year term i n i t i a l l y , with the option to renew each year thereafter. The project i s required to provide a minimum amount of kilowatt-hours (kWh) per year. The purchase rate i s currently set at 3.0 cents/kWh for the f i r s t year, plus adjustments each year a f t e r that equal to changes i n the Consumer Price Index (CPI) for Vancouver, but not exceeding 3 percent/year. To secure a contract with B.C. Hydro, the IPP must be able to: 1) demonstrate, through previous experience and/or performance guarantees, an a b i l i t y to design, finance, construct, and operate the proposed project; 2) meet the standards for e l e c t r i c i t y quality, r e l i a b i l i t y of supply, and safety, and be compatible with the B.C. Hydro system; 30 3) pay for interconnection costs and required modifications to ex i s t i n g B.C. Hydro f a c i l i t i e s ; 4) pay fee(s) to B.C. Hydro to a s s i s t i n defraying i t s costs of evaluating the proposal; 5) obtain a l l necessary approvals, licences, and permits to comply with a l l regulatory requirements. B.C. Hydro's p o l i c i e s with respect to IPPs are presented i n more d e t a i l i n Appendix 4. There are several major differences between the under-5- MW process and the over-5-MW process worth noting. Following a public RFP process, B.C. Hydro w i l l purchase e l e c t r i c i t y from projects greater than 5 MW at rates and other terms based on competitive negotiations, provided that the q u a l i t y i s acceptable and the cost to B.C. Hydro i s lower than the cost of other a v a i l a b l e alternatives. The e l e c t r i c i t y purchase p r i c e and other conditions for these projects w i l l be negotiated and B.C. Hydro w i l l seek f i n a n c i a l arrangements which optimize benefits to the u t i l i t y and i t s ratepayers. B.C. Hydro w i l l consider a l t e r n a t i v e p r i c e structures and/or financing arrangements, with appropriate guarantees, to a s s i s t these projects. The competitive negotiation process i s outlined i n Appendix 4. The intent of t h i s process i s to negotiate a p r i c e that provides the lowest cost to B.C. Hydro ratepayers and r e f l e c t s 31 the values of firm and secondary energy. Factors a f f e c t i n g p r i c e include: - dependability and r e l i a b i l i t y of energy supply; - duration of supply; - impact on the transmission and d i s t r i b u t i o n system (e.g., proximity to the Lower Mainland). Performance guarantees may be required to reduce the r i s k , both front-end and operational, to B.C. Hydro. 3.3 : Progress to Date While B.C. Hydro borrowed from lessons learned from other u t i l i t i e s i n the U.S. and Ontario i n s e t t i n g t h e i r p o l i c y for the over-5-MW projects, for the under-5-MW process they seem to be allowing the policy to evolve gradually. For the i n i t i a l Request for Proposals for under 5 MW released i n May 1989, B.C. Hydro received responses from 10 firms, a l l based i n B.C., representing 14 hydroelectric projects, with a t o t a l capacity of 47.6 MW. These projects are scattered throughout the province. While representatives of B.C. Hydro f e e l that purchase agreements w i l l be entered into with most of the project sponsors, as of March 1990 only one contract, a small 62 kW project representing less than 1% of the t o t a l capacity offered, had been signed. There are several factors which may account f o r t h i s lack of action i n B.C.: price for power produced, a l l o c a t i o n of s i t e s on Crown land, environmental concerns, and the 32 regulatory process. However, the main obstacle to the development of these proposed projects seems to be the p r i c e offered by B.C. Hydro for the power the projects w i l l generate. Industry representatives f e e l the purchase p r i c e i s too low and that many of the proposed projects are not economically f e a s i b l e at the rate offered. These small hydro projects are being offered a standard 2 0 year contract and a standard p r i c e for energy, which i s now set at 3.0 cents/kWh beginning the year the project comes on l i n e and escalating at a rate equal to changes in the Vancouver CPI or 3% per year, whichever i s l e s s . Presumably, the o f f e r i n g of a low rate i n i t i a l l y aims to l i m i t the number of projects and get the energy at the lowest possible p r i c e . There are several problems with t h i s p r i c i n g p o l i c y . While the 3.0 cents/kWh rate was f i r s t announced i n June 1988, there has been no provision to escalate i t with i n f l a t i o n up to the i n - s e r v i c e date of the project, which could be 1991 or l a t e r . The longer i t takes to negotiate and secure a contract, the less revenue, i n r e a l terms, the developer w i l l receive. This e s p e c i a l l y becomes a cause for concern for developers when B.C. Hydro i s responsible f o r delays. The e s c a l a t i o n rate, which does not s t a r t u n t i l one year a f t e r the i n - s e r v i c e date, i s set at a maximum of 3% per year, yet i n f l a t i o n has averaged 5.7% per year and the cost of e l e c t r i c i t y has escalated 4.5% per year for the past 25 years (Synex, 1990, p.3). The 3.0 cents/kWh figure i s also less 33 than B.C. Hydro's value of firm e l e c t r i c i t y , and lower than purchase rates i n Ontario and Alberta of 3.97 ($1989) and 4.64 ($1990) cents/kWh respectively, which escalate at the rate of i n f l a t i o n over the l i f e of the contract. Thus, the question i s r a i s ed whether or not t h i s i s a f a i r p r i c i n g p o l i c y for small hydro projects under 5 MW. To answer t h i s question, I w i l l now examine the cost of hydroelectric energy i n more d e t a i l . 34 CHAPTER 4 : PRICING HYDROELECTRIC ENERGY 4.1 : P r i n c i p l e s of Energy Pr i c i n g The c h a r a c t e r i s t i c s of e l e c t r i c i t y d i s t r i b u t i o n and transmission are such that the industry i s most e f f i c i e n t l y operated when a monopoly i s granted to an e l e c t r i c a l u t i l i t y . As a r e s u l t , there i s no free market f o r e l e c t r i c a l energy and the u t i l i t y i s a monopsonist. In most cases i t i s not possible nor f e a s i b l e for an IPP, e s p e c i a l l y a small power producer, to s e l l power to any other buyer. Rates thus have to be set by processes other than the free i n t e r p l a y of market forces. Most people would agree on the following p r i n c i p l e s : - the rates for power from each project should be as low as possible for maximum benefit to the u t i l i t y ' s customers, and they should c e r t a i n l y be no higher than the u t i l i t y ' s avoided cost; - the rates paid for the power should be s u f f i c i e n t l y high to a t t r a c t developers, allow them to finance t h e i r projects, and encourage them to innovate; the r i s k s associated with the development, financing, and operation of each project should be f a i r l y a l l o cated between the developer and the u t i l i t y . D i f f i c u l t i e s i n deciding on f a i r rates of payment aris e from the c a p i t a l intensive nature of hydro developments which necessitates a long term energy purchase contract to secure 3 5 the financing; the d i f f e r e n t methods f o r financing private developments and those of a major u t i l i t y ; the u t i l i t y ' s monopoly on the purchase of energy, which precludes the s e t t i n g of rates by competition i n the marketplace; and the uncertainties associated with the long-term horizons of power contracts, including i n f l a t i o n , i n t e r e s t rates, taxes, construction and operating costs, etc. The demand for e l e c t r i c a l energy varies continuously. I f a u t i l i t y cannot meet the demand, some of i t s e l e c t r i c a l load must be "shed", r e s u l t i n g i n a power cut-off or a brownout. In North America, standards are high and u t i l i t i e s are most reluctant to shed loads except under emergency conditions. Thus, to meet the continuously varying loads the u t i l i t y must have enough capacity to meet the peak demand and enough "stored" energy to keep meeting the energy demands. Since each customer connected to the e l e c t r i c a l system has the " r i g h t " to use any amount of e l e c t r i c a l energy up to the capacity of the connection, the customer has a " c a l l " on a c e r t a i n amount of generating capacity, which i n theory i s dedicated to h i s or her use, whenever they want i t . There i s a cost to supply t h i s peak capacity c a p a b i l i t y , as well as a cost for supplying the actual amount of energy used. This cost i s passed on to customers i n Europe and large customers i n North America, who pay a demand charge based on t h e i r peak demand as well as an energy charge. With thermal generation, the peak demand charge depends on the cost of the generating 36 and transmission f a c i l i t i e s (usually the f i x e d c o s t s ) , and the energy charge depends on the amount of f u e l used for generation (the variable costs). With hydro power, the cost s p l i t i s not so clear cut, but the same p r i n c i p l e s apply. This adds to the complications of s e t t i n g f a i r rates f o r small plants that supply only part of the load. The rate offered for e l e c t r i c i t y should also r e f l e c t the length of the purchase contract and the r i s k s assumed by the developer. Obviously, a long-term contract with performance guarantees i s worth more than energy bought on a temporary or "spot" basis. I f a developer takes on the f i n a n c i a l and te c h n i c a l r i s k s of power plant construction and operation, the u t i l i t y benefits because i t i s able to lower i t s r i s k exposure. There are many d i f f e r e n t ways to pay for e l e c t r i c i t y over a long-term contract. Clearly, a small developer would prefer a higher rate i n the early years to service h i s debt and pay o f f h i s c a p i t a l , and could then accept lower rates, based on operating and maintenance costs only, i n l a t e r years. For example, the rate could be set such that c a p i t a l costs could be paid o f f i n the f i r s t 20 years of a contract, and, upon renewal, the rate would be decreased to r e f l e c t only operating and maintenance costs, provided that the payment stream has the same net present value as the value of power to the u t i l i t y f o r the same duration. However, there are r i s k s to the u t i l i t y i n such an arrangement i n that the plant may not 37 operate long enough for the u t i l i t y to benefit from the low- cost e l e c t r i c i t y promised in the future. While the u t i l i t y ' s customers benefit i n the short term from the lowest rates possible, i f the purchase p r i c e i s set too low, several problems may a r i s e . Projects that can produce power for less than the u t i l i t y ' s avoided cost w i l l not be b u i l t . The r i s k of the project f a i l i n g , e i t h e r f i n a n c i a l l y or t e c h n i c a l l y , i s increased as developers cut corners i n design and construction. Developers may not develop a s i t e to i t s maximum p o t e n t i a l , which i s not an e f f i c i e n t use of the resource, or they may be discouraged from innovating. In the attempt to reduce c a p i t a l costs, developers may be tempted to forsake operational and maintenance considerations i n the design stage, leading to higher operating costs i n the future. Thus, i t may be advantageous i n the long run for a u t i l i t y and i t s ratepayers to pay a l i t t l e more up-front for power, with the expectation of paying l e s s i n the future, for more e f f i c i e n t , r e l i a b l e , and l o n g - l a s t i n g private sector development. 4.2 : B.C. Hydro's Energy Costs There are many ways of valuing energy. There i s the value of energy based on h i s t o r i c a l costs, and that based on future costs. Future costs can be e i t h e r short-term marginal costs or long-term costs. Long-term costs can be broken down into firm energy and secondary energy. Firm energy can be 38 expressed i n terms of a "capacity" component and i n terms of an "energy" component. Because of a l l these d i s t i n c t i o n s , any discussion of energy costs must f i r s t define the type of energy. B.C. Hydro e s s e n t i a l l y has three sets of power pr i c e s : h i s t o r i c a l average costs, short-term marginal costs, and long- term marginal costs. I t now costs B.C. Hydro 4.4 cents/kWh (in 1989 dollars) to generate, transmit, and d i s t r i b u t e e l e c t r i c i t y (note that other costs discussed below are p r i m a r i l y production costs and do not include the cost of d i s t r i b u t i o n ) . Since B.C. Hydro's average cost of production i s based on h i s t o r i c a l c a p i t a l costs that are considerably less than today's replacement costs, average costs may not r e f l e c t the value of additional power to the system and instead we should examine the marginal costs of producing power. The short-term marginal value of power i s based on incremental production costs to the in-service date of the next plant or, i n other words, the cost to produce an extra kWh of e l e c t r i c i t y with the ex i s t i n g system. B.C. Hydro uses t h e i r short-term values for evaluating short-term project modifications as well as evaluating p o t e n t i a l power purchases and coordination agreements with other u t i l i t i e s . Thus, t h i s i s the p r i c e B.C. Hydro i s w i l l i n g to pay for power on a short-term or "spot" basis. The short-term value of energy w i l l increase over time, as a r e s u l t of i n f l a t i o n and also i n 39 r e a l terms as B.C.'s energy surplus diminishes. The value of t h i s energy r i s e s from 1.8 cents/kWh i n 1989 to 4.9 cents/kWh in 1999 (in 1989 dollars) as shown i n Table 3. Figure 4.1 shows the e f f e c t of i n f l a t i o n on the value of energy by displ a y i n g the same figures i n nominal d o l l a r s using B.C. Hydro's assumed long-term average annual i n f l a t i o n rate of 4.5%. TABLE 3 : B.C. Hydro's Marginal Value of Enercrv (cents/kWh i n constant 1989 dollars) Year Value of Firm Firm Secondary E l e c t r i c i t y Capacity Energy Energy 1989 1.80 0.12 1.70 1.10 1990 1. 80 0.12 1.70 1.10 1991 1.80 0.12 1.70 1.10 1992 1.90 0.12 1.80 1.10 1993 2 . 00 0.12 1.90 1.10 1994 2 .30 0.12 2.20 1.10 1995 2.20 0.12 2 .10 1.10 1996 2.80 0.12 2.70 1.30 1997 3.40 0.12 3.30 1.50 1998 4.20 0.12 4.10 1.70 1999 4.90 0. 48 4.40 1.90 2000 and on 5.00 0.48 4.50 2.00 Source: B • CH. 's "Value of E l e c t r i c i t y " (August 1989) Although i t i s usually customary to ignore the e f f e c t s of i n f l a t i o n and work with real d o l l a r figures, I w i l l work mostly with nominal d o l l a r s for several reasons: 40 FIGURE 4.1 : B.C. Hydro's Marginal Value of Energy Source: BCH's "Value of Electricity" (August 1989) - i t i s useful to i l l u s t r a t e how costs and energy values change due to i n f l a t i o n over a long period of time; Net Present Values calculated with nominal d o l l a r s and a nominal discount rate are equal to those calculated with r e a l d o l l a r s and a r e a l discount rate ; B.C. Hydro's constant d o l l a r figures are calculated using an assumed long-term rate of i n f l a t i o n . The long-term value of power i s a time-weighted average cost of future projects included i n B.C. Hydro's Resource Plan. This i s B.C. Hydro's projected value of future power generation. B.C. Hydro's long-term l e v e l i z e d value of firm e l e c t r i c i t y i s 5.0 cents/kWh i n 1989 d o l l a r s . There i s a difference between firm energy, which can be r e l i e d upon, and secondary energy, which i s not guaranteed and as such i s worth s l i g h t l y l e s s . Firm energy i s the assured energy output i n kWh of a hydro generating plant over one year. B.C. Hydro defines the firm c a p a b i l i t y of i t s system as the annual energy avai l a b l e during an extended period of below average streamflows (what they c a l l the c r i t i c a l period). In other words, firm energy i s the minimum annual output of a hydro plant under extremely low streamflows. Firm energy can be broken down into two components and priced accordingly: 42 1) Dependable Capacity This i s valued on the basis of peak capacity, measured i n $/kW/year, and expressed i n the equivalent cents/kWh. In the short term, B.C. Hydro bases the value of capacity on recent marketing opportunities for t h e i r surplus capacity which i s about 0.1 cents/kWh ($1989). The value of capacity i n the long term i s based on the cost of adding more peaking capacity (but not more t o t a l energy output) to the e x i s t i n g system (at the Mica and Revelstoke projects) and t h i s cost i s equivalent to 0.5 cents/kWh ($1989). 2) Dependable Energy This i s the value of the energy component, which B.C. Hydro calculates by subtracting the value of capacity from t h e i r t o t a l long-term value of e l e c t r i c i t y . The incremental value of firm energy i s estimated at 4.5 cents/kWh ($1989). B.C. Hydro defines i t s value of firm e l e c t r i c i t y as the sum of the values of firm capacity and firm energy. Secondary energy i s the energy that i s a v a i l a b l e over and above firm energy when water conditions are favorable. Secondary energy may not always be a v a i l a b l e and cannot be "guaranteed" or r e l i e d upon. Its long-term value i s presently estimated to be 2.0 cents/kWh ($1989). Figure 4.1 shows the 43 long-term value of firm and secondary energy i n nominal d o l l a r s . The value of small hydro energy output i s rel a t e d to how "dependable" i t i s . That i s , whether the energy i s always av a i l a b l e when i t i s required. Output of t h i s nature has "capacity value". I f , on the other hand, the output i s ava i l a b l e independent of system requirements, then the value corresponds to the marginal costs of the system at the time the output i s available. This i s termed the "energy value". Because of the nature of small hydro power, often only the energy value, with no capacity value, i s a t t r i b u t e d to the output of small hydro plants (Sigma, 1983, p.2-6). I w i l l discuss t h i s concept i n more d e t a i l i n Chapter 5. 4.3 : Avoided Costs When a u t i l i t y purchases power from an independent producer, i t displaces the cost of acquiring power from other sources. The avoided cost i s the cost that would otherwise be incurred i f the u t i l i t y had to generate the power i t s e l f or purchase from another u t i l i t y . By buying power from small producers, the u t i l i t y can delay, at l e a s t temporarily, planned new generating f a c i l i t i e s and "avoid" t h e i r associated costs. In the absence of a competitive market for the supply of e l e c t r i c i t y , avoided costs would seem to be a f a i r basis for s e t t i n g a price for purchasing power from independent producers, and t h i s i s the accepted standard i n the U.S. and 44 Ontario. The purchase of power at a u t i l i t y ' s avoided cost i s also, i n theory, economically e f f i c i e n t . To t h i s end, B.C. Hydro has recently adopted a p o l i c y of meeting future energy needs at the "lowest t o t a l resource cost" and t h i s can be achieved "by setting the c e i l i n g p r i c e for a l l resource ac q u i s i t i o n s , regardless of o r i g i n , at the avoided cost of new e l e c t r i c i t y " (B.C. Hydro, November 1989, p.13-3). There can be a problem, however, i n actually determining avoided costs, e s p e c i a l l y long-term costs. Long-term avoided costs may be based on a s p e c i f i c avoided plant, a t h e o r e t i c a l "proxy" plant, an aggregate of costs from a l l potential future projects, or other more complicated means. B.C. Hydro, f o r example, presently bases t h e i r long-term avoided costs on the time-weighted, average l e v e l i z e d cost of future projects. Determination of avoided costs should be r e l a t i v e l y simple and easy to understand on the one hand, and reasonably accurate and r e a l i s t i c on the other. Given uncertainties i n future load demands, technology development, i n t e r e s t rates, i n f l a t i o n , environmental requirements, etc., determining costs beyond the next planned project with any p r e c i s i o n i s d i f f i c u l t . The only cost estimates that may be reasonably r e l i a b l e w i l l be those of the next plant to be b u i l t . Thus, I suggest basing long-term avoided costs on the cost of the next planned project. This method i s simple i n that complicated formulas or computer models do not have to be used. I t i s 45 accurate i n the sense that guesses such as what type, what si z e , how expensive, and when w i l l they be needed, do not have to be made about a multitude of future plants. B.C. Hydro's next major generating f a c i l i t y i s well documented: i t w i l l be the 900 MW S i t e C h y d r o e l e c t r i c project on the Peace River i n Northern B.C. which could come on-line as e a r l y as 1999 (note that the addition of up to 240 MW of generating capacity at the e x i s t i n g Keenleyside Dam w i l l l i k e l y be b u i l t f i r s t and capacity additions are planned for several other e x i s t i n g hydro s i t e s ) . 4.3.1 : Avoided Costs of Site C The cost of building B.C. Hydro's next large generating plant, S i t e C, i s included in B.C. Hydro's long-term value of power. Table 4 shows Site C project costs and we can determine the avoided costs of Site C as follows. C a p i t a l costs include estimated construction costs, corporate overhead, interest during construction, and i n f l a t i o n during construction. B.C. Hydro's f i x e d operating costs include: - operation and maintenance; insurance; administration and general expenses; grants (in l i e u of property taxes); interim replacement costs. 46 TABLE 4 : S i t e C Proiect Specifications and Costs Peak Capacity: 900 MW Firm Energy Output/yr.: 4570 GWh Average Energy Output/yr.: 4710 GWh Total C a p i t a l Cost: $2053 M i l l i o n ($1989) Annual Fixed Cost: $33 M i l l i o n ($1989) Annual Variable Cost: $17 M i l l i o n ($1989) Levelized Unit Energy Cost: 4.71 cents/kWh ($1989) Assumptions: Discount Rate 4.5%, Project comes on l i n e period, 70 year l i f e . = 12.85%, I n f l a t i o n Rate = in 1999, 7 year construction Source: B.C.H's "20 Year Resource Plan" ( A p r i l 1989) and "Value of E l e c t r i c i t y " (August 1989) and Appendix 5. Generating f a c i l i t i e s on the Peace and Columbia River system are exempted from paying school tax and B.C. Hydro does not pay income tax. Variable operating costs f o r a hydro plant b a s i c a l l y c onsist of the energy portion of the water r e n t a l fees, which i s 0.4 cents/kWh. Water rental fees are charged by the p r o v i n c i a l government for use of the province's water. In contrast, a thermal plant's variable operating costs would include p r i m a r i l y fuel costs. However, a thermal plant i s not required to pay for the a i r i t consumes. I t should be noted that since the province owns B.C. Hydro, costs such as grants i n l i e u of taxes and water re n t a l 47 fees are not r e a l l y costs i n a true economic sense but tr a n s f e r s back to the government (and, i n turn, back to the c i t i z e n s who are also B.C. Hydro's customers). However, since B.C. Hydro passes these types of costs d i r e c t l y on to the ratepayer and i t i s the t o t a l d i r e c t cost to the ratepayer that w i l l ultimately determine the value of IPP power, for the purposes of t h i s paper I w i l l t reat such items as r e a l costs. Figure 4.2 show these costs over the expected 70 year l i f e of the project i n nominal d o l l a r s . Capital costs are assumed to be incurred at the beginning of the f i r s t year of operation. , Annual fixed and variable operating costs are assumed to be incurred at the end of each year, and r i s e at the rate of i n f l a t i o n . 4.3.2 : D i f f e r e n t Accounting for S i t e C Costs The costs of S i t e C and other future projects are usually stated as a l e v e l i z e d rate over the l i f e of the project. I t takes t o t a l c a p i t a l cost and fixed and v a r i a b l e operating costs over the l i f e of the project, and, using a discount rate net of i n f l a t i o n , determines an equivalent annual cost i n constant d o l l a r s . In other words, i t takes the Net Present Value of a l l c a p i t a l and operating cash flows, and spreads i t out over the l i f e of the project. Levelized cash flows for S i t e C are shown in Figure 4.3 i n nominal d o l l a r s , which s t a r t o f f i n Year 1 as the l e v e l i z e d cost and escalate at the rate 48 2.0 -< 1.9 -) 1.8 -> s s / \ / \ / Discount Rate = 12.85% Inflation = 4.5% Year 1 in 1989$ Capital Cost Variable Costs Fixed Costs Fixed Costs Year \//A V a r . C o s t s N/N Capital Cost FIGURE 4.2 : Site C Project Cash Flows 5.0 4.5 4.0 - 3.5 3.0 - = 2.5 2.0 1.5 - 1.0 - 0.5 $ 2 2 2 M - 0.0 Discount Rate = 12.85% Inflation Rate = 4.5% Year 1 in 1989$ NPV = $2645 M s Levelized Costs ' s / 7\ K n / \ / ' \ \ / ' \ s / / ^ / s / \ \ / / s \ / s ' ' s 'I I ' T i i r I r i I i ] 1 i f i i V I i I | t i " I l I i f 10 20 30 40 Year K X I Levelized Cost 50 60 70 FIGURE 4.3 : Site C Levelized Cash Flows of i n f l a t i o n over the l i f e of the project. B.C. Hydro uses l e v e l i z e d costs i n determining t h e i r long-term avoided costs. However, the l e v e l i z e d cost does not represent actual expenditures by B.C. Hydro for power. To pay for the c a p i t a l cost of the project, B.C. Hydro would borrow by issuing long- term debt and then pay o f f the loan over time. I f the c a p i t a l costs are amortized over the l i f e of the project, 70 years, the c a p i t a l costs are depreciated at a constant rate each year for 70 years, assuming s t r a i g h t - l i n e depreciation. Real expenditures would consist of i n i t i a l l y high, but declining, i n t e r e s t payments, a constant depreciation (sinking fund) cost, and r i s i n g operating costs, as shown i n Figure 4.4 (after McDonnell, 1989). However, only a large u t i l i t y or government agency could afford to account f o r costs over such a long time frame i n t h i s way. A private company would use a much shorter depreciation term, paying o f f c a p i t a l costs i n 20 years, f o r example, as shown i n Figure 4.5. In t h i s case, i n t e r e s t payments and depreciation costs stop a f t e r year 20, leaving only r i s i n g operating costs for the remainder of the project's l i f e . A 20 to 3 0-year depreciation term i s more reasonable for several reasons: the e f f e c t s of discounting beyond t h i s time span are n e g l i g i b l e , e.g., cash flows discounted back 20 years at 12% are only worth 10% of t h e i r future value; 51 Year F^Cost Y//\ Var.Cost Depr. ^ int. FIGURE 4.4 : Site C Cash Flows - 70 Yr. Depreciation SSS] FbcCost V7A Var.Cost Year D e p r . R\^i Int. FIGURE 4.5 : Site C Cash Flows - 20 Yr. Depreciation - the r i s k s and uncertainties beyond t h i s time span become incalculable, e.g., who knows what i n t e r e s t rates, i n f l a t i o n , and power demand w i l l be 1 year from now l e t alone 20 years; - other sources of power may be developed i n the future that may be s i g n i f i c a n t l y cheaper or le s s harmful to the environment, rendering the present project obsolete and uneconomic; B.C. Hydro does not issue bonds f o r terms greater than 25 years, r e f l e c t i n g investors' maximum time horizon. Dividing the t o t a l annual costs by the average annual energy output gives an annual unit energy cost. Although B.C. Hydro bases i t s long-term unit costs on firm energy output, unit costs f o r in d i v i d u a l hydroelectric projects are based on average energy c a p a b i l i t y . Average annual energy output includes some secondary energy and i s thus s l i g h t l y greater than firm energy output. B.C. Hydro estimates the l e v e l i z e d u n i t energy cost for S i t e C as 4.71 cents/kWh i n 1989 d o l l a r s . This rate s t a r t s o f f at 4.71 and escalates at the rate of i n f l a t i o n over the l i f e of the project. These three methods of cost accounting for S i t e C - l e v e l i z e d cost, 70-year depreciation term, and 20-year depreciation term - are shown i n Figure 4.6, which shows 54 FIGURE 4 . 6 : Different Accounting Costs for Site C nominal annual unit energy costs with year 1 i n 1989 d o l l a r s . A l l three cash flows have the same Net Present Value (NPV). The c a l c u l a t i o n of these cash flows uses data from B.C. Hydro's reports "20 Year Resource Plan" ( A p r i l 1989) and "Value of E l e c t r i c i t y " (August 1989) including an assumed discount rate of 12.85% and a long-term, average annual i n f l a t i o n rate of 4.5%. The 70 and 20-Year Depreciation l i n e s are based on actual expenditure p r o f i l e s i n which a greater proportion of the c a p i t a l costs would be paid up front. As l e v e l i z e d costs do not represent actual expenditures by the u t i l i t y , they do not represent costs that are passed onto the ratepayer. Thus, for choosing between d i f f e r e n t projects, l e v e l i z e d costs may be an appropriate measure, but for setting a purchase rate they are not. I suggest that the 20-Year Depreciation l i n e i s the most r e a l i s t i c r e f l e c t i o n of Site C s avoided costs for comparison with p r i v a t e sector projects. 4.4 : Suggested Avoided Cost P r o f i l e As discussed e a r l i e r , B.C. Hydro presently bases i t s avoided cost on i t s short and long-term marginal costs i n which the long-term costs are based on the average l e v e l i z e d cost of future projects as shown i n Figures 4.1 and 4.7. I propose that, for the purposes of s e t t i n g a p r i c e for independent power purchases, avoided costs be based on short- term marginal costs (STMC) and the cost of the next plant. 56 FIGURE 4.7 : Avoided Cost Profiles (1992-2021) The cost of the next plant should be calculated by depreciating the c a p i t a l costs over the f i r s t 20 years of the plant's l i f e . An avoided cost p r o f i l e can then be generated as shown i n Figures 4.7 and 4.8. Avoided costs are based on STMC up to 1998 and then jump up to Si t e C's avoided costs i n ,1999. This avoided cost p r o f i l e can be used to set rates for small power projects that come on-line up to the time at which the avoided plant begins operation. When the next major plant f i n a l l y does come on-line, a new p r o f i l e would be generated based on the next scheduled plant. A u t i l i t y should be w i l l i n g to pay an IPP a rate that has a NPV equal to or less than t h e i r avoided cost stream over the same period. B.C. Hydro has adopted t h i s approach and recently said that the c e i l i n g p r i c e to be paid an IPP should be based on the "equivalent present value" of t h e i r "avoided costs f o r the same block of e l e c t r i c i t y " (B.C. Hydro, Nov. 1989, p.1-3-9). For example, for a 20-year contract s t a r t i n g i n 1992, the NPV of the purchase p r i c e over the 20-year period would be equal to the NPV of the avoided costs over the same period. 4.5 : Comparison with B.C. Hydro's Offer As an example, l e t ' s look at a project coming on l i n e i n 1992, which i s the e a r l i e s t a small hydro plant could be i n service i f a developer signed a contract today. To keep 58 FIGURE 4.8 : 20 Year Purchase Rates Starting in 1992 administrative costs low for both i t s e l f and p o t e n t i a l developers, B.C. Hydro i s o f f e r i n g standard 20 year contracts for projects less than 5 MW. The purchase rate presently being offered a small power producer i s 3.0 cents/kWh, escalating at 3% per year, as shown i n nominal d o l l a r s i n Figure 4.8. This i s the price for a l l energy, both firm and secondary. Over the 20-year l i f e of the contract, the NPV to B.C. Hydro of the purchase price i s 2 5.6 cents per kWh of average annual output compared to a NPV of 4 6.9 cents/kWh fo r the avoided cost stream (in 1992 d o l l a r s ) . Thus, the small power producer would only be receiving a l i t t l e over h a l f of what i t would cost B.C. Hydro to produce i t s own power over the same period ( i f the u t i l i t y repaid i t s c a p i t a l costs within 20 years as the private producer must). To make the purchase rate equivalent to the avoided cost rate over the 20 years, i t would have to s t a r t out at a base rate of 5.0 cents/kWh and escalate at the rate of i n f l a t i o n (assumed to be 4.5%) as shown i n Figure 4.8. A l t e r n a t i v e l y , a f i x e d rate of 6.6 cents/kWh could be offered. The NPVs to B.C. Hydro of the avoided cost and purchase rate would now be equal. Of course, the rate may have to be adjusted for factors such as firmness and r e l i a b i l i t y of energy supply and transmission costs, but the general p r i n c i p l e s t i l l applies. 60 As shown i n Figure 4.8, B.C. Hydro would pay more than i t s avoided cost for power i n the early years of the contract, but would pay considerably less i n the l a t e r years. Thus, the proposed rate i s front-loaded compared to the avoided costs. This proposed rate would allow small hydro developers to pay off t h e i r c a p i t a l costs over the term of the contract. Using t h i s same technique of matching the NPV of the purchase p r i c e to the NPV of the avoided cost stream for the same time period, a purchase rate schedule could be developed as shown i n Table 5 in nominal d o l l a r s . This rate increases each year up to the time Site C comes on l i n e , at which point new small hydro projects would be receiving a rate, before adjustments, that i s equivalent to the f u l l avoided cost of S i t e C. This ensures that a l l small hydro projects costing the same or les s than Site C are b u i l t f i r s t , with the e f f e c t of pushing S i t e C as far into the future as possible. The increasing rate also helps to ensure that development i s gradual, with lower cost s i t e s being b u i l t f i r s t . Table 5 also includes rates based on B.C. Hydro's l e v e l i z e d long-term costs which would be equivalent to t h e i r suggested c e i l i n g price for IPP power. These rates are lower than the suggested rates. The 1989 base rate of 3.97 cents/kWh escalating at i n f l a t i o n offered i n Ontario i s higher than the suggested 1989 rate of 3.72 and considerably higher than what B.C. Hydro would be o f f e r i n g . Alberta's 1990 base rate of 4.64 cents/kWh i s also higher than the suggested 1990 61 rate. In both Ontario and Alberta, however, rates are based on l e v e l i z e d avoided costs, not accounting costs, and t h e i r avoided costs could be quite d i f f e r e n t than B.C. Hydro's. B.C. Hydro's rates are discussed i n more d e t a i l i n the next chapter. TABLE 5 : Enercrv P r i c i n g Rates 1989 - 1999 (in cents/kWh i n nominal dollars) 20 Year Suggested Schedule Schedule Based Contract (20 yr. Depr. of on B.C. Hydro's S t a r t i n g Avoided Plant's Levelized Long i n Year Capital Costs) Term Costs Base Rate Fixed Base Rate Fixed Esc.@Infl Paymt Esc.@Infl Paymt 1989 3 .72 4.93 3 .14 4.16 1990 4.10 5.44 3.46 4.59 1991 4 . 52 6.00 3 . 83 5. 08 1992 4.99 6. 62 4 .23 5.62 1993 5.49 7.28 4 . 68 6.20 1994 6.02 7.99 5.16 6.85 1995 6.58 8.72 5.66 7.51 1996 7.20 9.54 6.23 8.27 1997 7.79 10.34 6.79 9.00 1998 8.35 11.08 7.31 9.69 1999 8.84 11.72 7.75 10.28 Discount Rate = 12. 85%, I n f l a t i o n Rate =4.5% 62 CHAPTER 5 : VALUE OF SMALL HYDRO POWER 5.1 : Discussion of B.C. Hydro's Small Hydro Rate Offer Not only i s the value of B.C. Hydro's small hydro energy purchase rate lower than that of the proposed rate based on the methods outlined i n Chapter 4, but i t i s also s i g n i f i c a n t l y l e s s than the value of B.C. Hydro's own suggested c e i l i n g p r i c e . The net present values of d i f f e r e n t 20-year energy purchase contracts are compared i n Table 6. For projects coming on-line i n 1992, the NPV of B.C. Hydro's suggested c e i l i n g p rices, based on t h e i r l e v e l i z e d long-term costs, i s 39.8 cents/kWh, which i s 56% higher than the NPV of 25.6 cents/kWh of t h e i r small hydro price o f f e r . The question then a r i s e s , "What i s the basis for the 3.0 cents/kWh o f f e r ? " From discussions with B.C. Hydro representatives, i t appears the 3.0 cents/kWh figure i s not based on any hard data or rigorous c a l c u l a t i o n s , but rather i s an a r b i t r a r y number greater than t h e i r estimated short-term marginal costs of approximately 2.0 cents/kWh and less than the long-term l e v e l i z e d cost which was about 4.0 cents/kWh when the purchase p r i c e was f i r s t set. The 3.0 cents/kWh figure was f i r s t proposed i n 1988 and to date there has been no provision for adjusting i t for i n f l a t i o n up to the time the f i r s t projects w i l l come on-line or for changes i n B.C. Hydro's marginal costs. For example, i n A p r i l 1989 B.C. Hydro's long-term value of power was stated as 3.8 cents/kWh i n 1988 d o l l a r s and 63 i n August 1989 i t was changed to 5.0 cents/kWh i n 1989 d o l l a r s . Although there was a 32% increase i n the value of energy, no adjustment was made to the small hydro purchase p r i c e . The value of t h i s rate i s c l e a r l y less than B.C. Hydro's present avoided costs for energy. TABLE 6 : Comparison of Purchase Rates Net Present Values of 20-year Contracts Cents per kWh of Annual Output i n Nominal Dollars (in Starting Year $) Contract A B C D E S t a r t i n g Proposed BCH BCH Firm Second. i n Year Rate C e i l i n g Offer Energy Energy 1989 35.0 29.5 25. 6 27. 4 13.5 1990 38.6 32.6 25.6 30.1 14.6 1991 42.5 36.0 25.6 33.3 15.8 1992 46.9 39.8 25. 6 36.7 17.1 1993 51.6 44.0 25.6 40.5 18.5 1994 56.6 48 . 5 44.6 20.4 1995 61.8 53.2 48.8 21.9 1996 67.7 58.6 53 . 6 23 . 8 1997 73 . 3 63.8 58. 1 25.7 1998 78.6 68.7 62.2 27.4 1999 83 . 1 72.9 65. 6 29.1 A : Proposed Rate based on 20 Yr. depreciation of avoided plant costs B : Rates based on B.C. Hydro's short and long-term marginal costs, long-term costs are l e v e l i z e d C : B.C. Hydro's Under 5 MW o f f e r D : Rates based on B.C. Hydro's value of Firm Energy only E : Rates based on B.C. Hydro's value of Secondary Energy only NPV of Ontario o f f e r of 3.97 cents/kWh s t a r t i n g i n 1989 = 37.3 NPV of Alberta o f f e r of 4.64 cents/kWh s t a r t i n g i n 1990 = 43.6 64 There are several reasons to explain B.C. Hydro's reluctance to pay f u l l avoided cost for small hydro power. F i r s t , they believe power from small hydro has l i t t l e firm capacity and t r e a t i t as mostly secondary energy. Second, there i s the perception that buying power from small producers i s " r i s k y " and the power source i s u n r e l i a b l e . Third, they want to pay as l i t t l e as possible for private power to reduce the cost to the consumer and not allow developers to receive "windfall p r o f i t s " at the consumers' expense. However, no hard data has been provided to support t h i s corporate stance. I w i l l now examine each of these three points i n more d e t a i l . 5.2 : Firm Capacity of Small Hydro Most small hydro plants are run-of-the-river plants. In other words, the energy produced from a run-of-the-river plant w i l l fluctuate with streamflow. Energy production w i l l vary with season and the seasonal v a r i a t i o n w i l l depend on geographical location. For example, i n the south coast region, energy production i s greatest during the winter months when much of the p r e c i p i t a t i o n f a l l s as r a i n . According to Sigma's study, energy production could average i n excess of 60% of i n s t a l l e d capacity for eight months of the year for t h i s region (Sigma, 1983, p.1-2). This i s based on the weighted average output of a l l s i t e s i n the region i d e n t i f i e d i n Sigma's study and assumes that each plant i s sized to be at f u l l generation capacity f o r the mean annual flow of the p a r t i c u l a r stream. Production f a l l s to about 40% 65 of i n s t a l l e d capacity during the summer months when p r e c i p i t a t i o n i s at i t s annual low. Energy production p r o f i l e s for various regions i n B.C. are shown i n Figure A6-2 in Appendix 6. The production p r o f i l e s of the north coast and i n t e r i o r regions are d i f f e r e n t because a greater proportion of the p r e c i p i t a t i o n f a l l s as snow, which i n turn a f f e c t s stream flow patterns. In contrast to the south coast s i t e s , the lowest production rates are i n the winter months f o r these two regions. The impact of spring runoff i s r e f l e c t e d i n the higher production rates which reach maximum values during June and July. The influence of the spring freshet i s dominant i n the i n t e r i o r , where many of the s i t e s reach maximum production capacity during the same month (June). The north coast s i t e s a t t a i n a second maximum during the l a t e f a l l when the p r e c i p i t a t i o n has not yet turned to snow. During the winter months, t y p i c a l l y December to March, average monthly production w i l l f a l l to about 25% and 40% of i n s t a l l e d capacity f o r i n t e r i o r and north coast s i t e s r e s p e c t i v e l y . Thus, small hydro plants w i l l be operating at les s than f u l l capacity during s i g n i f i c a n t portions of the year. In i t s study, Sigma defined a "firmness factor", which i s the expected annual energy production of a plant divided by the maximum possible production ( i n s t a l l e d capacity i n kW x 8760 hours/year) , and t h i s factor can be estimated f o r any given s i t e . Figure A6-1 i n Appendix 6 shows estimated firmness 66 factors for d i f f e r e n t regions i n the province. In general, the firmness factor i s higher for coastal s i t e s (average value of 0.6) than for the i n t e r i o r s i t e s (average value of 0.5). In i t s IPP purchase rate schedule, Ontario Hydro uses a monthly "capacity factor", which i s determined by d i v i d i n g the t o t a l kWh delivered i n a month by the maximum possible monthly production (maximum monthly kW delivered x the number of hours i n the month). Projects with a capacity factor of 65% or more receive f u l l avoided costs while projects with le s s than 65% receive a rate based on the short-term incremental energy costs. Note the difference between average output expressed as a percentage of i n s t a l l e d capacity and firm energy expressed as a percentage of average outputw. For example, while the i n s t a l l e d capacity of Site C i s 900 MW, i t s average annual output would only be 60% of the maximum possible output or: 60% x 900 MW x 8760 hours/year = 4710 GWh per year but i t s firm annual energy output would be 97% of i t s average annual output: 97% x 4710 GWh per year = 4570 GWh per year. Although the output of many small hydro projects would vary with streamflow, and as a r e s u l t l i t t l e or no capacity value would be attributed to t h e i r output, there would be some plants with firm capacity and the energy of these plants 67 should be valued accordingly. Regardless, B.C. Hydro has stated that i t "needs energy, not capacity" (B.C. Hydro, Nov. 1989, p. 1-3-16) and i t i s possible to determine the value of the energy component only. B.C. Hydro has estimated i t s short-term and long-term values of capacity as 0.1 cents/kWh and 0.5 cents/kWh res p e c t i v e l y (see Table 3). Subtracting the capacity values and using only estimated firm energy values for avoided costs, the NPV of a 20-year contract s t a r t i n g i n 1992 i s 36.7 cents/kWh, s t i l l considerably higher than the standard p r i c e o f f e r (see Table 6) . The NPV of secondary energy over t h i s same time span i s 17.1 cents/kWh. I f firm energy output was hal f of average annual output, in other words 50% of the t o t a l energy produced i n a given year was firm and 50% secondary, the NPV of t o t a l energy produced would be 26.9 cents/kWh, j u s t s l i g h t l y higher than the price o f f e r . Under these conditions, and using B.C. Hydro's l e v e l i z e d cost data, the 3.0 cents/kWh o f f e r might be reasonable. Thus, the 3.0 cents/kWh rate would penalize those small hydro projects with more than 50% of average output as firm energy. In contrast, S i t e C's firm energy i s 97% of the average energy output. Ken Peterson, B.C. Hydro's Director of Planning, i n response to questions about the firm energy c a p a b i l i t y of small hydro i n B.C., stated, " . . . i t ' s probably well under 50%" (McDonnell, 1990, p.4). Yet, as an example, the average output of B.C. Hydro's 702 kW Clayton F a l l s plant i n Bel l a 68 Coola i s i n excess of 80% of i t s i n s t a l l e d capacity, i n contrast to 60% for S i t e C (McDonnell, 1990, p.4). While the performance of the Clayton F a l l s plant may not be representative of a l l small hydro plants, i t does demonstrate that small hydro can have firm energy c a p a b i l i t y meeting or exceeding that of larger scale projects. B.C. Hydro has also stated i n i t s RFPs that they would prefer projects capable of supplying more than 50% of t h e i r t o t a l annual energy delivery in the months of November to A p r i l , when t h e i r e l e c t r i c i t y demand i s highest. As mentioned above, small hydro s i t e s on the south coast would produce a majority of t h e i r power during t h i s time period. Thus, B.C. Hydro should be w i l l i n g to pay more, not l e s s , for power supply that matches t h e i r demand. In i t s standard contract for projects under 5 MW, B.C. Hydro requires the developer to d e l i v e r a minimum amount of energy per year. This amount would be, according to B.C. Hydro's d e f i n i t i o n , the firm energy c a p a b i l i t y of the plant. By including t h i s provision i n the contract, B.C. Hydro i s assuming the plant has firm energy c a p a b i l i t y and thus, they should be w i l l i n g to pay f u l l price for t h i s energy. Thus, there i s evidence that small hydro plants have firm energy c a p a b i l i t y , but how much and what kind would be t y p i c a l of a small hydro plant are areas that require further study. 69 5.3 : Risk and R e l i a b i l i t y When a u t i l i t y buys power from an IPP, i t does not assume any of the construction or operating r i s k s and i t i s only required to pay for power produced. However, the u t i l i t y does run the r i s k s of the project being delayed, abandoned, or not producing energy i n the quantity or qu a l i t y for which i t contracted. Some of these r i s k s can be mitigated through contract provisions such as performance guarantees and low flow insurance. The Ontario government, for example, believes the r i s k s of independent power production are manageable and outweighed by the benefits. The Alberta Small Power Inquiry adopted the view that small power projects pose l i m i t e d r i s k to the public and the e l e c t r i c a l system, and only by encouraging the development of such projects i n the near term would they be able to properly assess the impacts of small projects, including r i s k and r e l i a b i l i t y , i n the longer term. Overall, the u t i l i t y could reduce i t s r i s k exposure for energy production, and t h i s should increase the value of IPP power. In regard to the r i s k of a n o n - u t i l i t y project not being completed, i t i s i n t e r e s t i n g to note that 35,370 MW of c o a l - f i r e d and 73,130 MW of nuclear power planned by u t i l i t i e s i n the U.S. have been cancelled since the passage of PURPA (Meade, Jan. 1989). In 1986, P a c i f i c Gas and E l e c t r i c , a C a l i f o r n i a u t i l i t y , reported that firm capacity of n o n - u t i l i t y generators had an average capacity factor of 95% as opposed to 60% f o r the average u t i l i t y base load plant (Meade, Jan. 70 1989) . Thus, the assertion that independently produced power i s l e s s r e l i a b l e than u t i l i t y produced power i s questionable. Admittedly, the small hydro resource i s unproven, and the question of r e l i a b i l i t y i s a v a l i d one that requires more research. However, from a t o t a l system perspective, many small hydro plants may be more r e l i a b l e than an equivalent large one. For example, i f a plant of 5 MW or less did not perform as expected, the e f f e c t on the system would be n e g l i g i b l e . I f , on the other hand, a large 200 or 300 MW project was not completed as planned, the u t i l i t y might f i n d i t s e l f short of power. Because small hydro plants connected to the integrated g r i d would be spread over a wide geographical area, the chances of more than a few experiencing low flows, operating problems, or routine maintenance at the same time i s low. However, low flows i n j u s t the Peace River system, f o r example, would simultaneously a f f e c t 35% of B.C. Hydro's capacity. Thus, r i s k and r e l i a b i l i t y must be examined from a system perspective as well as on a project-by-project basis. Asked to indicate the basis f o r the skepticism of B.C. Hydro as to the r e l i a b i l i t y of firm energy from small hydro producers, Mr. Peterson responded, " I t ' s primarily a fact that many of these plants are on streams that have no r e l i a b l e streamflow records." (McDonnell, 1990, P.4) While i t i s true that with l i t t l e or no streamflow data the r e l i a b i l i t y of a small hydro plant can not be proven, i t i s not true that i t 71 means the plant w i l l be unreliable. I t i s probably safe to assume hydrological studies would be performed to determine the r e l i a b i l i t y of streamflows before a developer invested m i l l i o n s of d o l l a r s developing a small hydro s i t e . 5.4 : Windfall P r o f i t s The question of windfall p r o f i t s i n the p r i v a t e sector i s a contentious issue for a u t i l i t y to t a c k l e . I f a private developer can produce power at or l e s s than a u t i l i t y ' s avoided cost and s t i l l make a large p r o f i t , instead of t r y i n g to reduce the p r i c e paid to the developer, the u t i l i t y should perhaps examine i t s own cost e f f i c i e n c y . B.C. Hydro i s not i n a p o s i t i o n to d i c t a t e rates of return to the p r i v a t e sector. B.C. Hydro does not pay income tax, and on some projects does not pay school tax, on the revenue i t earns; private producers do. School taxes alone amount to about 0.5 cents/kWh (McDonnell, 1990, p.3). For a given block of energy, a larger percentage of the revenues accrue to the taxpayer, who i s also the ratepayer, from p r i v a t e l y produced power than from u t i l i t y produced power. For example, for a t y p i c a l IPP project, over a 20-year contract paying 4.0 cents/kWh escalating at i n f l a t i o n , about 28% of the revenues would accrue to the government through various taxes, 25% would go to the banks as in t e r e s t charges, 31% would go to operating costs and paying o f f the p r i n c i p a l , while the developer would only receive 17% (McDonnell, 1990, p.4). This 72 corresponds to a return on after-tax income of 15%, assuming no cost overruns, construction delays, or water shortages. Thus, the government and taxpayers appear to be the "windfall" winners. If the plant did not operate as planned, the public i s not required to b a i l out the developer; the developer has assumed much of the r i s k and, i n return, expects compensation. If , however, B.C. Hydro has a cost overrun or builds a plant that i s not immediately required, i t i s the ratepayers who pay. As well, most Canadian u t i l i t i e s are subsidized i n one form or another while IPPs are not (Passmore, 1987, p.14). For example, B.C. Hydro has i t s loans guaranteed by the p r o v i n c i a l government, r e s u l t i n g i n s l i g h t l y lower borrowing rates. Although no money changes hands, there i s a cost to the government for assuming t h i s r i s k (Nickerson, 1989). B.C. Hydro has also received f i n a n c i a l contributions from the government i n "aid of construction." Thus, given that private producers and u t i l i t i e s are not competing on a " l e v e l playing f i e l d , " i t seems only appropriate that IPPs are given the opportunity to earn a healthy p r o f i t . In conclusion, there i s no data to support B.C. Hydro's under 5 MW p r i c e o f f e r . Although I agree with the concept of a standard p r i c e , provisions should be made for : - escalation of the rate with i n f l a t i o n up to the i n - service date of the plant; 73 - changes i n the rate corresponding to changes i n the u t i l i t y ' s avoided costs; - standard rate adjustments for firmness, r e l i a b i l i t y , and r i s k exposure. While some projects may lack firm energy and be p o t e n t i a l l y u n r e l i a b l e , good projects that can demonstrate firm energy and r e l i a b i l i t y should not be penalized and should be e l i g i b l e to receive a f a i r rate for t h e i r power. 74 C H A P T E R 6 : ENERGY P R I C I N G P O L I C Y FOR S M A L L HYDRO POWER 6.1 : Sucrcrested P o l i c y From the above general concepts and the experience i n the U.S., Ontario, and Alberta, I have developed a suggested general p o l i c y for energy purchases from small hydro producers. Small hydro power purchase rates could be set according to the following proposed two-stage process. 6.1.1 : F i r s t Stage In the f i r s t stage, the f i r s t 10 years or so, the u t i l i t y would i n v i t e proposals from would-be developers and, provided the proposed projects met well-defined f i n a n c i a l , t e c h n i c a l , and environmental requirements, o f f e r them a standard contract to purchase energy. The 2 0-year contract term proposed by B.C. Hydro i s reasonable and b e n e f i c i a l to both the u t i l i t y and the developer. (a) Purchase Rate Schedule A standard rate schedule would be used i n the f i r s t stage. This schedule would be based on B.C. Hydro's avoided cost p r o f i l e with the purchase rates having the same Net Present Value as the avoided cost over the 2 0-year contract. The avoided cost p r o f i l e would be based on the short-term marginal costs up to the projected in-service date of the next plant. A f t e r t h i s point the avoided costs would be based on 75 the accounting cost of the next plant assuming the c a p i t a l costs are amortized over the f i r s t 20 years of operation. This rate schedule should c l e a r l y set a s t a r t i n g rate for the i n - s e r v i c e year, a contract duration, and, i f required (see below), an escalation rate. The schedule would be updated each year on the basis of changes i n projected discount and i n f l a t i o n rates, and the timing and costs of the avoided plant. This schedule would be used to e s t a b l i s h prices for projects coming on-line up to the i n - s e r v i c e year of the avoided plant. A f t e r t h i s point a new avoided cost p r o f i l e would be used based on the new short-term marginal costs and the avoided costs of the next scheduled plant. Avoided costs, purchase rates, and the methods for determining them should be subject to an on-going or periodic public review by an independent body with the necessary f i n a n c i a l and technical resources. (b) Choice of Two Purchase Rates The purchase rate schedule would o f f e r the choice of two payment schedules: a base rate i n the f i r s t year of operation escalating at the actual rate of i n f l a t i o n each year thereafter, or a fixed uniform rate over the l i f e of the contract based on an assumed rate of i n f l a t i o n . This gives the developer some f l e x i b i l i t y i n financing and managing 76 r i s k s . For example, i f the developer f e l t actual i n f l a t i o n would be higher than that assumed for c a l c u l a t i n g the fixed rate, he might choose the escalating rate; i f he could secure more favorable financing terms with a front-loaded contract, he might choose the fixed rate. (c) Rate Adjustments The rate would be adjusted, by r e l a t i v e l y simple, standardized methods, on a project-by-project basis depending on a number of factors including: firmness and r e l i a b i l i t y of power supply (for example, based on annual or monthly firm capacity). It should be possible to adjust t h i s a f t e r the plant i s i n operation based on actual operating performance; - l o c a t i o n of project and associated transmission losses; environmental and s o c i a l impacts; - r i s k s assumed by private developer including changes i n : i n f l a t i o n and i n t e r e s t rates; taxes and water rentals; regulatory and environmental requirements; demand load; c l i m a t i c events, e.g., low streamflows. 77 Adjustments for firmness are discussed i n more d e t a i l i n Appendix 6. B.C. Hydro would adjust the rate downwards for r i s k s i t was required to assume. Changes i n taxes would include the introduction of the federal government's proposed Goods and Services Tax (GST). For r i s k s such as streamflows, the developer may decide to acquire insurance to compensate B.C. Hydro for low water l e v e l s , or the developer might be w i l l i n g to pay penalties for low output as the r e s u l t of low streamflows. (d) Capacity Requirements In the f i r s t phase, a l l projects meeting the s p e c i f i e d requirements would be accepted. In other words, there would be no capacity cap. However, to prevent the u t i l i t y and the various government agencies from being swamped with a flood of proposals, some r e s t r i c t i o n s could be placed on applications such as only two or three from any one developer i n the system at one time, or l i m i t i n g the number or t o t a l capacity of applications accepted for review on a monthly or annual basis. 6.1.2 : Second Stage A f t e r 10 years or so (for example, when S i t e C i s on- line) , and the IPP industry has established i t s e l f , a standard rate schedule would again be used but pr i c e s would be based on the market value of e l e c t r i c i t y , e.g., what i t could be bought for from larger IPPs or other u t i l i t i e s . Assuming that a competitive negotiation or bidding process would be i n place 78 for projects over 5 MW, that e l e c t r i c a l energy production i n Alberta and the U.S. Northwest would undergo further deregulation, and that B.C. Hydro would increase cooperation and integration with adjacent u t i l i t i e s , i t should be much easier to e s t a b l i s h a market value f o r e l e c t r i c i t y i n the future. For example, the unadjusted p r i c e f o r under 5 MW projects could be t i e d to the lowest (or highest) winning or negotiated p r i c e from an over 5 MW RFP. A l t e r n a t i v e l y , i f the industry i s competitive enough, a competitive bidding or negotiation process may be set i n place, i n which the u t i l i t y would accept the proposals that would provide energy at the lowest cost, up to the t o t a l amount required, provided the cost d i d not exceed the u t i l i t y ' s avoided cost. However, because of the expense and time to B.C. Hydro and private developers of negotiating and administering such a process, i t would l i k e l y not be cost e f f e c t i v e for small projects. At t h i s point a capacity cap may be set each year depending on system load requirements, but t h i s may not be necessary given the r e l a t i v e l y small contribution of under 5 MW projects. 6.2 : Policy Rationale The main rationale for t h i s two-stage approach i s the persuasive argument put forward by the Independent Power Producers i n Ontario, namely that the f i r s t aim should be to 79 develop a viable small hydro industry. Later, when the industry becomes well established, i t could be possible to have competitive bidding for s i t e s and contracts, which would ensure fairness, e f f i c i e n c y , and the benefits of rate competition i n the long run. As pointed out e a r l i e r , i t i s time consuming and expensive to prepare a competitive proposal for developing a hydro s i t e or negotiate a contract with the u t i l i t y . These costs can be handled more e a s i l y by a company that has already developed a few small hydro plants, since by that stage, i t would need to be well organized, well financed and well beyond the l e v e l of a "Mom and Pop" operation. But they cannot be e a s i l y handled by a small company at i t s s t a r t - up stage. Another reason for a two-stage process i s the view taken by the ERCB and PUC i n the Alberta Small Power Inquiry: the best way to determine the c a p a b i l i t y , impact, and pote n t i a l contribution of small power producers i s to encourage t h e i r development i n the short-term and review the r e s u l t s at a future date. This process would help answer questions regarding the firm energy c a p a b i l i t y , r e l i a b i l i t y , and r i s k of small power production based on actual operating data rather than conjecture. The projects are small enough that r i s k s to the public and e l e c t r i c a l system are minimal during the i n i t i a l stage and the res u l t s of the review could be used to fine tune the second stage process. 80 To encourage development and get the small hydro industry on a firm f i n a n c i a l basis, the u t i l i t y should be generous i n the early stages and o f f e r prices at or close to i t s avoided costs. This i s an accepted standard i n Ontario and Alberta and a cornerstone of PURPA l e g i s l a t i o n i n the U.S. The payment of avoided cost allows the u t i l i t y to e x p l o i t a l l other sources of energy that cost the same or l e s s than the avoided cost a l t e r n a t i v e . Basing the avoided cost on depreciating the c a p i t a l costs of the avoided plant over 20 years, the maximum period that would be acceptable for p r i v a t e l y owned developments, and using a 20-year contract term ensures that a developer could pay o f f the c a p i t a l costs of an economic project within the l i f e of the purchase agreement. This should r e s u l t i n the rapid build-up of a strong, well-financed small hydro industry with a supporting i n f r a s t r u c t u r e of designers, builders, manufacturers, and suppliers that should strongly benefit the p r o v i n c i a l economy. This should also lead to the provision of low cost e l e c t r i c i t y i n the future. Although i t appears that many j u r i s d i c t i o n s i n the U.S. are moving towards a competitive bidding process, the benefits of the standard avoided cost price for the f i r s t 10 years of PURPA are c l e a r l y v i s i b l e i n the rapid growth of the multi- b i l l i o n d o l l a r independent power industry. The industry would l i k e l y never have developed i n a u t i l i t y c o n t r o l l e d market without the PURPA avoided cost l e g i s l a t i o n . The industry i s 81 now mature enough to continue to prosper under a more competitive environment. Representatives of B.C. Hydro point to the s i t u a t i o n i n C a l i f o r n i a where .avoided costs dropped and u t i l i t i e s were required to continue to pay PURPA projects higher rates for power the u t i l i t i e s did not necessarily need at that time. However, i t should be recognized that many of the projects b u i l t under PURPA were powered by renewable resources such as hydro, wind, solar, and geothermal whose output could displace that of p o l l u t i n g , non-renewable thermal plants. I t i s possible that avoided costs could once more r i s e dramatically even higher than the rates now being paid under long-term contracts to independent producers. Expensive u t i l i t y - sponsored nuclear power plants were mothballed or never completed, yet c a p i t a l costs i n some cases were s t i l l passed on to consumers for power that w i l l never be produced. Clea r l y , ratepayers and the rest of C a l i f o r n i a society w i l l b enefit i n the long run from paying higher rates to PURPA projects i n the short run. Thus, paying f u l l avoided costs for independent power has been successful i n the " f i r s t stage" of development i n the U.S. and using C a l i f o r n i a as an example of the dangers of paying f u l l avoided costs i s not r e a l l y a v a l i d argument. One drawback to paying f u l l avoided cost based on 20-year depreciation of the u t i l i t y ' s c a p i t a l costs i s the r i s k that the plant does not operate for the f u l l 20 years of the 82 contract and beyond, so the u t i l i t y does not benefit from the lower energy costs in the future. As well, there has to be incentive for the owner of the plant to maintain the plant i n good working order over the term of the contract so that i t w i l l continue to operate for more than 20 years. To ensure that they can take advantage of low energy prices a f t e r 20 years, B.C. Hydro should have the option to renew the contract at a p r i c e r e f l e c t i n g the avoided cost of operation and maintenance only or at the going market rate for power, whichever i s l e s s . They may also wish to include an option to purchase the plant for one d o l l a r at the end of the 20-year contract or an option to assume ownership i f the plant, once i t begins operation, shuts down before the contract ends, or i f the owners f a i l to maintain i t to a c e r t a i n l e v e l of q u a l i t y . I f the u t i l i t y pays a front-loaded uniform rate based on f u l l avoided cost, calculated using the proposed method, the developer should not require, nor should he receive, any subsidies or tax exemptions. In the early stage, s i m p l i c i t y i s important. Thus, although the " f a i r " price to be paid for energy should depend on the l o c a l conditions and probably should be "custom f i t t e d " through a negotiation process, i n p r a c t i c e a standard rate should be offered to a l l small power producers, with standard adjustments for firmness, location, etc. 83 A l i m i t on the number of proposals that should be accepted from one group at any one time would be a safeguard against one or two larger groups t r y i n g to "corner the market" and would help prevent too many s i t e s being developed at once. Although the aim would be to encourage several strong, capable, well financed groups, no one group should be allowed to dominate. 84 CHAPTER 7 : SUMMARY AND CONCLUSIONS 7.1 : Conclusions Although B r i t i s h Columbia has a s i g n i f i c a n t p o t e n t i a l small hydro resource and the development of t h i s resource by independent power producers could provide many benefits, i n pra c t i c e there has been very l i t t l e progress. The major obstacle seems to be the small hydro p r i c i n g p o l i c y of B.C. Hydro, the p r o v i n c i a l e l e c t r i c a l u t i l i t y . Despite i t s o f f i c i a l p o l i c y of encouraging independent power and the commitment of the p r o v i n c i a l government to private energy development, B.C. Hydro seems to be having d i f f i c u l t y i n adjusting from i t s t r a d i t i o n a l role as a monolithic monopoly with complete control over power generation, transmission and d i s t r i b u t i o n , to i t s new role as a competitive producer, purchaser, and manager of energy resources. The d i f f i c u l t i e s i n getting development going centre around questions of fairness and equity, not te c h n i c a l issues. B.C. Hydro seems to be doing everything possible to obtain contracts f o r the purchase of e l e c t r i c a l energy at minimal cost, with the laudable aim of minimizing the pric e s they must charge t h e i r customers. However, the p r i c e they are o f f e r i n g for small hydro power i s s i g n i f i c a n t l y less than t h e i r avoided costs and there i s l i t t l e evidence to j u s t i f y t h i s rate. I contend that i t would be better to o f f e r p r i v a t e power producers a more generous rate i n the early stages that 85 r e f l e c t s actual avoided costs, to b u i l d up the f i n a n c i a l and technical capacity of the industry without increasing costs to ratepayers. I believe that i n the long term the province would benefit more from a capable, well-financed, competitive private power industry, than from a short-term p o l i c y of squeezing small developers and r i s k u n d e r u t i l i z i n g the resource or l o s i n g i t altogether. The p o l i c i e s I have suggested are not intended to be the only or the best solutions but rather to act as a c a t a l y s t for further discussion. Some of the present p o l i c i e s seem to have been formulated i n a vacuum and the r e s o l u t i o n of these problems w i l l only come with more dialogue. B.C. Hydro, the affected government bodies, and representatives from the small hydro industry should s i t down and hammer out a p o l i c y that i s equitable to a l l parties and that w i l l maximize the benefits of developing the small hydro resource. 7.2 : Suggestions for Further Research There are several areas of small hydro p r i c i n g p o l i c y i n which further research would shed l i g h t on some unanswered questions: 1) Firm Capacity and Energy c a p a b i l i t i e s of small hydro plants; 2) Risks and R e l i a b i l i t y of IPPs i n general and small hydro power i n p a r t i c u l a r ; 3) Competitive Bidding and Negotiation Processes. 86 Information gained from research into these areas could be used to develop a f a i r and equitable small hydro energy p r i c i n g p o l i c y . Although I ju s t mentioned them i n passing, the following p o l i c y issues w i l l undoubtedly be factors a f f e c t i n g the future success of small hydro development: 4) S i t e A l l o c a t i o n on Crown land and water l i c e n s i n g implications (who gets the opportunity to develop which s i t e s ) ; 5) Environmental Impact of small hydro plants and other resource planning issues; 6) Regulatory Process for small hydro projects. These l a s t three issues are under review at the moment by the Ministry of Energy, Mines, and Petroleum Resources. Although the under-5-MW projects are supposed to have a streamlined regulatory process, indications are that i t w i l l become more complicated. Requiring the developer to spend more time and money i n the application and approval process w i l l quickly make feasible small hydro projects uneconomic. Further research into these p o l i c y issues may a s s i s t i n determining whether or not the benefits of addit i o n a l regulation ( i f there are any) outweigh the costs. Although most of the problems facing small hydro developers at t h i s time are economic and p o l i c y related, t e c h n i c a l improvements and innovation w i l l help the industry 87 survive i n the long term. Although not complete, I suggest the following two areas: 7) C a p i t a l Cost Reductions such as designing for low cost construction and use of a l t e r n a t i v e low cost materials and equipment; 8) Operational E f f i c i e n c y such as improved intake designs and more e f f i c i e n t turbines and generators. By reducing c a p i t a l costs and improving e f f i c i e n c y , small hydro can become more competitive with l a r g e r projects and al t e r n a t i v e sources of energy. 88 R E F E R E N C E S "Alberta Agencies Recommend Small Power be Encouraged." Hydro Review, August 1988, p. 78. Alberta M i n i s t r y of Transportation and U t i l i t i e s . "Major Program to Help Small Power Producers i n Alberta." Ministry News Release, June 14, 1988. Alberta Ministry of Transportation and U t i l i t i e s . "Improvements Announced to Small Power Program." Ministry News Release, November 8, 1989. B.C. Hydro. "Guidelines for P r i c i n g of Resource Ac q u i s i t i o n s . " B.C. Hydro and Power Authority Rate Application, November 30, 1989. B.C. Hydro. Value of E l e c t r i c i t y . Resource Planning, August 1989. B.C. Hydro. I n v i t a t i o n for Proposals: Purchase of E l e c t r i c i t y (Projects Under 5 MW) for B.C. Hydro's Integrated System, May 1989. B.C. Hydro. Twenty-Year Resource Plan, A p r i l 1989. Brown, Ruben. "Projecting Capacity." Independent Power, January 1989, p. 22. C r o l l , Geoffrey and S.O. Russell. "Private Hydropower Development i n B r i t i s h Columbia." Proceedings of the Canadian Water Resources Association 43rd Annual Conference. May 1990. Eden, L e s l i e . "An Overview of the Implementation of PURPA." Waterpower '85, American Society of C i v i l Engineers, 1985, pp. 582-592. Eden, L e s l i e . "Hydro's Coming of Age." Hydro Review, August 1989, p. 12. Energy Resources Conservation Board and Public U t i l i t i e s Board of Alberta. Small Power Inquiry - Report to the Lieutenant Governor i n Council. Calgary, February 1988. Gregoris, Laurie, L. Moore, and P. Carrie. " S e l l i n g Power to Canadian U t i l i t i e s . " Hydro Review, December 1989, pp. 18-22. H a l l , Joe H. "Water, Energy, and the Future of Hydropower." Hydro Review. August 1988, p. 24. 89 Hesse, Martha. "100,000 More Megawatts by Year 2000." Al t e r n a t i v e Sources of Energy, October 1988, p. 58. Hesse, Martha. " P U R P A Revisited." A l t e r n a t i v e Sources of Energy, July 1987, p. 2. Hocker, Christopher. "Leading the Way i n Hydropower." Hydro Review, December 1989, pp. 10-16. Independent Power Producers' Society of Ontario. "Preferred Plan Delayed." IPPSO Facto (Newsletter of the Independent Power Producers' Society of Ontario), September 1989, pp. 3-7. Lewis, Brian. "Jobs, environment i n ; tax giveaways are out." The Province, A p r i l 8, 1990, p. 37. Lewis, Brian. "Private power p r i o r i t y . " The Province f A p r i l 5, 1990, p. 42. McDonnell, Glen. Presentation to B.C. Hydro Rate Application Hearing on behalf of the Independent Power Producers of B.C., February 23, 1990. McDonnell, Glen. Long Term Provincial Power Cost and the Pote n t i a l for Development of Independent Power Projects. Synex Energy Resources Ltd., October 1989 (unpublished). Marier, Donald. "Challenges for a New Decade." Independent Energy. January 1990, p. 2. Marier, Donald. "The Road to Success." Independent Energy, January 1990, pp. 10-14. Marier, Donald 1989. "A Banner Year." Independent Energy, November 1989, pp. 14-20. Marier, Donald. "Looking Ahead." Independent Power. January 1989, p. 2. Meade, B i l l . "Meeting Future Power Needs." Independent Energy, A p r i l 1989, pp. 18-22. Meade, William. "NIEP Takes on the Issue of R e l i a b i l i t y . " Independent Power, January 1989, p. 57. Nickerson, Dave. Commerce 576 Lecture. University of B r i t i s h Columbia, Vancouver, November 22, 1989. Ontario Hydro. Non-Utility Generation Power Purchase Rates. May 1989. 90 Ontario Ministry of Energy. "Pro v i n c i a l P o l i c y on P a r a l l e l Generation." IPPSO Facto (Newsletter of the Independent Power Producers' Society of Ontario), Special Release, July 25, 1989, p p . 1-8. Ontario Ministry of Natural Resources. Waterpower S i t e Release: Pol i c y and Procedures, November 1988. Ontario Ministry of Energy. Streams of Power: Developing Small Scale Hydro Systems. Renewable Energy i n Canada Ltd., 1986. Passmore Associates International. The Private Power Option for Canada. October, 1987. Ross, Deborah J . Correspondence from the Washington State U t i l i t i e s and Transportation Commission, December 6, 1989. ^ Shaffer, Marvin and Associates Limited and Sigma Engineering Limited. E l e c t r i c i t y Deregulation and Small Hydro Preliminary Assessment. Energy Mines and Resources Canada, December 1987, pp. 40-42. Sigma Engineering Limited. Small Hydro Power Resource i n the Pr o v i n c i a l System - Technology and Resource Assessment. B.C. Ministry of Energy, Mines and Petroleum Resources, July 1983. Sigma Engineering Limited and Robinson Consulting Limited. Small Hydro Power Resource i n the P r o v i n c i a l System - Economic and Financial Assessment. B.C. Ministry of Energy, Mines and Petroleum Resources, July 1983. Stoiaken, Larry. "FERC Reinterprets PURPA." Alt e r n a t i v e Sources of Energy, May 1988, pp. 17-19. Swoboda, Don. "IPP Status Report." Speech given at IPP Workshop, Vancouver, Tuesday, A p r i l 4, 1990. Synex Energy Resources Limited. The Potential for Development of Independent Power Projects Using a Contract Modelled Af t e r the Rate Application - Intervention to the B.C. Hydro and Power Authority Rate Application Dated November 30, 1989. January 1990. Washington State Energy O f f i c e . Power Sales to E l e c t r i c U t i l i t i e s - PURPA Qualifying F a c i l i t y Development i n Washington State. February 1989. 91 APPENDIX 1 BACKGROUND ON T H E P U B L I C U T I L I T I E S REGULATORY P O L I C I E S A C T (PURPA) PURPA Pr i o r to the enactment of PURPA, an independent power producer seeking to s e l l e l e c t r i c i t y to a u t i l i t y or d i r e c t l y to industry faced three major obstacles. F i r s t , u t i l i t i e s were not required to interconnect with the producer or to purchase that producer's e l e c t r i c a l output. Second, even i f a u t i l i t y was w i l l i n g to purchase e l e c t r i c i t y , the p r i c e offered by the u t i l i t y might not r e f l e c t f a i r market value. F i n a l l y , a small power producer was p o t e n t i a l l y subject to extensive u t i l i t y regulation. PURPA amended the Federal Power Act to reduce or eliminate these and other obstacles to the development of small power projects. In e f f e c t , PURPA requires u t i l i t i e s to interconnect with q u a l i f y i n g f a c i l i t i e s (QFs) located i n t h e i r service t e r r i t o r i e s and to purchase power at a p r i c e based on the u t i l i t y ' s f u l l avoided cost for energy and capacity. PURPA also exempts small power producers (SPPs) from c e r t a i n federal and state u t i l i t y regulations. SPPs q u a l i f y under PURPA i f the project meets s p e c i f i e d s i z e , f u e l use, and ownership c r i t e r i a . Cogeneration projects must also meet additi o n a l operating and e f f i c i e n c y standards. Legal Challenges Because of the uncertainties posed to the u t i l i t y industry by the Public U t i l i t i e s Regulatory Act (PURPA), the mandate to purchase power from such unproven, u n t r a d i t i o n a l sources of energy as small power producers became the focus of some extensive l e g a l battles i n the early years of PURPA implementation. PURPA and FERC's implementation of PURPA have been l e g a l l y challenged on such issues as infringement on states r i g h t s , establishment of avoided costs, interconnection requirements, provision of back-up power, and the d e f i n i t i o n of a Qualifying F a c i l i t y (QF) . These challenges have produced considerable uncertainty for u t i l i t i e s , project developers, and state u t i l i t y commissions. Two court cases challenged the authority of PURPA and FERC's i n t e r p r e t a t i o n of the Act. The f i r s t case, i n M i s s i s s i p p i , raised the question of the c o n s t i t u t i o n a l i t y of PURPA, arguing that PURPA interfered with state regulatory authority. A f t e r appealing a decision of a lower court i n February 1981 that declared the rules under PURPA 92 unconstitutional, FERC was successful i n having the U.S. Supreme Court uphold PURPA in June 1982. During t h i s time, another case also threatened the v i a b i l i t y of PURPA. A private u t i l i t y f i l e d a s u i t challenging FERC's rules on avoided cost and interconnection requirements, arguing that the f u l l avoided cost rate discriminated against the consumer and was therefore i n d i r e c t c o n f l i c t with the intent of the l e g i s l a t i o n ( f u l l avoided cost i s the cost the u t i l i t y would incur by purchasing or developing an additional unit of energy and capacity). I f the s u i t was successful, avoided cost rates would be s u b s t a n t i a l l y reduced and small power production f a c i l i t i e s would be required to undergo c o s t l y and lengthy proceedings to achieve interconnection, e f f e c t i v e l y shutting down many development proposals. State implementation of PURPA slowed considerably during the two years the case was being fought i n the courts. However, a f t e r overturning a lower court decision, the Supreme Court affirmed FERC's rules i n May 1983, marking the end of the major l e g a l challenges to PURPA and allowing f i n a l state implementation of the Act's requirements. While recognizing that a f u l l avoided cost r u l e would not lower rates to consumers, the court noted i n t h i s case that ratepayers and the nation would benefit through decreased re l i a n c e on scarce f o s s i l fuels and more e f f i c i e n t use of energy. The court also found that, i n regard to FERC's interconnection rules, requiring small power producers to undergo the same regulatory process as u t i l i t i e s would be time consuming, expensive and non-productive. In May 1983, another challenge came from a c o a l i t i o n of environmental groups claiming that FERC had not considered the environmental impact of awarding QF status to hydropower projects requiring new dams. This action led to the passage of the E l e c t r i c Consumers Protection Act (EPCA) i n 1986 which put constraints on hydro projects by imposing a moratorium on PURPA benefits to f a c i l i t i e s requiring construction of a new dam. In 1988, FERC invalidated New York's 6 cents/kWh avoided cost. FERC found that t h i s minimum p r i c e for purchasing power, which had been set to encourage development, was improperly established at a l e v e l higher than the purchasing u t i l i t y ' s avoided cost. The Future of PURPA In the words of Martha Hesse, chairman of FERC, " c l e a r l y , PURPA...is here to stay. PURPA has evolved into something far beyond the expectations of i t s c r e a t o r s . . . i t has outgrown the ro l e of a li m i t e d energy conservation of program. Now PURPA needs to be updated to r e f l e c t what we have learned from the 93 experience" (Hesse, July 1987, and October, 1988). Thus, PURPA i s i n a state of t r a n s i t i o n . Some of the issues to be addressed by FERC and the U.S. Congress include: - bidding and competitive bidding procedures and the question of requiring u t i l i t i e s to bid; - allowing u t i l i t i e s to compete with QFs; - relaxing the regulatory burden of independent generators who do not meet the QF c r i t e r i a ; - increased transmission g r i d access; - regulatory reform and deregulation of the e l e c t r i c a l generation industry. In 1988, i n an e f f o r t to increase competition i n the e l e c t r i c power generation market, FERC issued Notices of Proposed Rulemakings (NOPRs) for changes to PURPA on three main issues. These were: guidelines for administratively determining f u l l avoided costs, regulations governing competitive bidding programs, and rules for es t a b l i s h i n g Independent Power Production f a c i l i t i e s (IPPs) which are not subject to PURPA fuel and e f f i c i e n c y r e s t r i c t i o n s . But, because of the go-slow approach urged by Congress and the resignation of Chairman Hesse i n October 1989, FERC s t i l l has not taken the long-expected action to make changes to PURPA rule s . FERC i s expected to continue to move slowly u n t i l the new chairman has time to develop p r i o r i t i e s for the agency. Moves to modify the Public U t i l i t i e s Holding Act (PUCHA) to allow the construction of power plants without the r e s t r i c t i o n s of PURPA are presently s t a l l e d i n Congress. Following reports released by the O f f i c e of Technology Assessment ( E l e c t r i c Power Wheeling and Dealing) and FERC ( E l e c t r i c i t y Transmission: R e a l i t i e s , Theory, and Poli c y Alternatives) i n 1989, industry representatives and regulators are debating increased access to the transmission g r i d . Thus, there w i l l c e r t a i n l y be changes made to PURPA and other r e l a t e d regulatory l e g i s l a t i o n , but what these changes w i l l be and what kind of e f f e c t they w i l l have remains to be seen. However, there i s strong support to make the e l e c t r i c a l generation industry more competitive and less regulated. Sources: Eden, 1985; Hess, 1987 and 1988; Marier, Nov. 1989; Stoiaken, 1988; WSEO, 1989. 94 APPENDIX 2 ONTARIO HYDRO'S SMALL POWER PURCHASE RATES There are four options for projects with capacities up to 5 MW: 1) Standard Energy Rate (a) Capacity factor (CF) of 65% or greater: 3.97 cents/kWh escalated each year at the Ontario Consumer Price Index (CPI) for up to 10 years from the in - s e r v i c e date. Thereafter, the base rate i s renegotiated. This rate i s presently based on 85% of Hydro's accounting costs for power, but when avoided costs exceed 8 5% of the accounting cost (1991) , t h i s rate w i l l be based on avoided costs. (b) CF of les s than 65%: 2.54 cents/kWh reviewed annually r e l a t i v e to Hydro's short term incremental energy costs. This rate r e f l e c t s the short term incremental energy costs to Hydro. (c) CF of less than 75% but greater than 50% (new hydro projects only): 3.97 to 2.54 cents/kWh based on s l i d i n g scale. (d) CF of les s than 50% (new hydro projects only): 2.54 cents/kWh. 2) Ten year Fixed Rate for New Renewable Resource Projects (a) CF of 65% or greater: 4.94 cents/kWh for 10 years for projects coming into service i n 1989. (b) CF of les s than 65%: 2.54 cents/kWh reviewed annually r e l a t i v e to short term incremental energy costs. (c) CF of less than 65% but greater than 50% (hydro projects only): 3.40 to 2.54 cents/kWh based on s l i d i n g scale. (d) CF of les s than 50% (hydro projects only): 2.54 cents/kWh. 95 3) Time D i f f e r e n t i a t e d Rates (a) Peak Hours: 5.87 (Winter) and 5.28 (Summer) cents/kWh escalated annually at CPI for up to 10 years. (b) Off-Peak Hours: 2.50 (Winter) and 1.72 (Summer) cents/kWh escalated annually at CPI for up to 10 years. 4) Ten Year Time Di f f e r e n t i a t e d Fixed Rate for New Renewable Resource Projects (a) Peak Hours: 6.96 (Winter) and 6.25 (Summer) cents/kWh for 10 years. (b) Off-Peak Hours: 2.97 (Winter) and 2.04 (Summer) cents/kWh for 10 years. D e f i n i t i o n s : Monthly capacity factor i s determined by d i v i d i n g t o t a l kWh delivered i n a month by the product of the maximum monthly kW delivered and the number of hours i n the month. Peak Hours are 7 a.m. to 11 p.m. weekdays; Off-Peak Hours are 11 p.m. to 7 a.m. weekdays, plus a l l weekends and public holidays. Winter i s defined as October through March; Summer i s defined as A p r i l through September. 96 APPENDIX 3 ALBERTA SMALL POWER INQUIRY The objective of the Public U t i l i t i e s Board (PUB) and the Energy Resources Conservation Board (ERCB) was "to inquire into, report upon, and make such recommendations as necessary or advisable respecting e l e c t r i c i t y generation by small power generators i n Alberta". The Boards were s p e c i f i c a l l y asked to determine: the s i z e and type of generators that should be c l a s s i f i e d as small power generators; the number, types, and capacities of small power generators and t h e i r t o t a l capacity that could be interconnected without negatively a f f e c t i n g the r e l i a b i l i t y of the system or the cost of e l e c t r i c i t y ; the p r i n c i p l e s and methods which should apply to the se t t i n g of a price or prices paid by the u t i l i t i e s for e l e c t r i c i t y produced by small power generators. Recommendations of the Boards The Boards' recommended that: 1) the Alberta Government allow and f a c i l i t a t e the production of e l e c t r i c i t y by independent producers i n p a r a l l e l with the Alberta interconnected system (AIS); 2) a l l power producers with generating c a p a c i t i e s of 2.5 MW or less at one s i t e be classed as small power producers (SPPs); 3) i n i t i a l l y , a maximum of 100 MW of small power capacity be interconnected, since t h i s would not negatively impact the r e l i a b i l i t y of the system nor would i t s u b s t a n t i a l l y increase the cost of e l e c t r i c i t y to the consumer; 4) the pri c e s paid to SPPs by u t i l i t i e s should be based on u t i l i t y long-term avoided costs i n order to ensure that prices to consumers would not increase. The prices should vary according to the r e l i a b i l i t y , a v a i l a b i l i t y , term of contract, and commencement of contract; 5) SPPs should be exempted from the provisions of the Public U t i l i t i e s Board Act and the E l e c t r i c Energy Act subject to obtaining, the consent of the ERCB p r i o r to constructing or operating a small power f a c i l i t y . 97 Avoided Cost - The only costs which can be avoided from now u n t i l the mid-1990's are variable f u e l , operating, and maintenance costs. Commencing i n about 1995, i t may be possible to defer c e r t a i n c a p i t a l additions and thus avoid the attendant c a p i t a l and fixed f u e l , operating, and maintenance costs. Purchase Price - In order that e l e c t r i c i t y prices to consumers are not increased, the prices paid by u t i l i t i e s for small power production should r e f l e c t the costs which the u t i l i t i e s would avoid over the l i f e of the contract with the small power producer. This can be achieved by determining prices based on (a) the year-by-year avoided costs or (b) a l e v e l i z e d p r i c e that has the same NPV as discounting the long- run avoided costs over the length of the contract. Contracts - Standard contracts should be developed by the u t i l i t i e s , i n consultation with the Small Power Producers Association, for as-available (secondary) and firm power purchases. The above recommendations should be reviewed i n 1994 or when 100 MW of small power has been interconnected, whichever occurs f i r s t . Views of the Boards on Related Matters: 1) Small power projects pose l i m i t e d l i a b i l i t y of f i n a n c i a l r i s k to the public and should be subject to a streamlined regulatory process. 2) No subsidies, by way of incentive p r i c e s and r e s u l t i n g extra cost to consumers, should be given to SPPs (but t h i s does not preclude any d i r e c t assistance that the government might' deem prudent as i n i t i a l encouragement to a new industry). 3) Socioeconomic benefits associated with small power projects, or a small power industry, should not be a consideration i n the derivation of buyback rates. Any such benefits can be more appropriately recognized through d i r e c t government i n i t i a t i v e s such as taxes or grants rather than through increasing power rates to the consumer. 4) E l e c t r i c u t i l i t i e s can make a s i g n i f i c a n t contribution to the development of a small power industry and should not be denied access to that industry. 5) 2.5 MW i s a p r a c t i c a l upper l i m i t to cover the majority of small power projects and small enough to be t e c h n i c a l l y f l e x i b l e and e a s i l y accommodated by the e l e c t r i c d i s t r i b u t i o n systems, with the a b i l i t y to 98 connect such f a c i l i t i e s with l i t t l e impact to i t s d i s t r i b u t i o n system. 6 ) Avoided Costs Avoided costs rather than h i s t o r i c costs should be used as the basis for determining prices since t h i s would better r e f l e c t the estimated value of capacity and energy when the SPPs would be added to the system. SPPs should receive f a i r value for the energy and capacity they would provide to the system as a substitute for what the u t i l i t i e s would l i k e l y impose i n t h e i r absence. Long-term avoided costs should be used as the s t a r t i n g point to determine prices for small power generation. The Board examined three methods f o r determining avoided costs: D i f f e r e n t i a l Revenue Requirements (DRR), Fuel Offset, and Proxy Plant methods. The f i r s t two are d e t a i l e d methods of estimating long-term avoided cost that use complex computer models and educated assumptions. The t h i r d i s a les s rigorous but s i m p l i f i e d method that u t i l i z e s information that i s read i l y a v a i l a b l e . The method chosen must be simple enough so that r e s u l t s could be e a s i l y v e r i f i e d and understood and s t i l l be f a i r to a l l p a r t i e s ; thus there w i l l be a trade-off between accuracy and s i m p l i c i t y . The Proxy Plant Method meets most of the requirements and was accepted f o r purposes of determining avoided costs. Some of the assumptions made i n determining avoided costs were: - avoided costs should be calculated net of income taxes rebates; - as a r e s u l t of connecting SPPs to the system, losses on the transmission system would be reduced, and avoidable transmission losses should be included; - u t i l i t y property taxes, insurance, and interim replacements are avoidable costs; - assumed i n f l a t i o n = 4.5%, discount rate = 11.5%, r e a l discount rate = 6.7%; - annual depreciation rate = 1/(useful l i f e ) . Based on the costs of the Proxy Plant and the above assumptions, annual l e v e l i z e d costs were calculated for the avoided plant. These costs r i s e at the rate of i n f l a t i o n over the l i f e of the plant. Avoided costs were then set as: 99 - marginal energy costs (variable f u e l , operating, and maintenance costs) up to expected in - s e r v i c e date of proxy plant (capacity addition); - l e v e l i z e d avoided cost of the Proxy Plant thereafter. 7) Purchase Price In order to ensure that e l e c t r i c i t y prices to consumers do not increase, the prices that u t i l i t i e s pay for small power production should not exceed the cost that the u t i l i t y avoids over the l i f e of the contract with an SPP. I f p r i c e s were determined based on the year-by-year avoided costs, most small power projects would be uneconomic, as financing of such projects i s contingent on a f i x e d / l e v e l price schedule. Instead, the u t i l i t y should provide small power capacity payments in advance of when that capacity i s a c t u a l l y required; t h i s can be achieved by determining a l e v e l i z e d p r i c e (fixed price) which, when discounted, equates to the long-run avoided costs over the term of each contract. Those SPPs which cannot provide firm power should have t h e i r capacity prorated downward in accordance with t h e i r expected capacity factor r e l a t i v e to the capacity factor of the proxy un i t ; however, i n i t i a l l y the same p r i c e w i l l apply to both firm and as-available (secondary) power; i t may be possible that some adjustment and a d i s t i n c t i o n i n prices between as-available and firm power may be necessary when the program i s reviewed. Prices should be developed for 10, 15, 2 0-year contracts; prices would vary with the term of contract and i t s commencement date (see Table A3-1 which shows recommended l e v e l i z e d p r i c e s ) . These prices would remain fixed for the duration of each contract commenced during that period. 8) The regulatory process applicable to SPPs should be s i m p l i f i e d , streamlined and expedited i n order to reduce the time, e f f o r t , and cost associated with obtaining regulatory approvals, and i n doing so, some degree of control must be maintained respecting environmental and safety matters. 100 TABLE A3-1 : Purchase Prices for Firm and Secondary Power as Recommended by the Alberta Small Power Inquiry For Contract Fixed Price i n cents/kWh Starting i n for Contract Duration of Year 10 Years 15 Years 20 Years 1989 1990 1991 1992 1993 1994 1, 2. 2 , 2. 3 . 3. 2 , 2 , 3 , 3 , 3 . 4, 2 , 3 , 3 , 3 , 4 . 4 , Source: "Small Power Inquiry", ERCB and PUC of Alberta, Feb. 1988, Table 4-1, p. 15. Government Implementation of the Boards' Recommendations: In response to the report, the Alberta government announced the "Small Power Research and Development Program" i n June 1988 and updated i t i n November 1989. The major differences between the Boards' recommendations and the government program were: - the 100 MW t o t a l capacity cap was raised to 125 MW; - the program was lim i t e d to renewable resources projects only; - u t i l i t i e s and t h e i r s u b s i d i a r i e s are not e l i g i b l e to p a r t i c i p a t e i n the program; - the purchase price was increased (5.2 cents/kWh u n t i l 1995 and 6.0 cents/kWh ther e a f t e r ) , e f f e c t i v e l y bringing the long term pr i c e forward to the present; - i n l i m i t i n g the program to renewable resources and increasing the recommended purchase pr i c e , the government considered the environmental benefits of renewables. I t i s also i n t e r e s t i n g to note that the p r o v i n c i a l government assisted the Small Power Producers Association with a grant of $100,000, matched by the federal government, to a s s i s t them i n making a f u l l representation to the hearing. 101 APPENDIX 4 B.C. HYDRO'S IPP ENERGY PURCHASE POLICY There are four areas of i n t e r e s t to the private power developer: 1) Domestic Use a) Non-Integrated area; b) Integrated system from projects under 5 MW; c) Integrated system from projects over 5 MW; 2) Export Market. This includes e l e c t r i c i t y released by load displacement. B.C. Hydro's IPP Policy Statement: "In i t s e f f o r t to achieve the most economic supply of e l e c t r i c i t y , B.C. Hydro (BCH) i s turning to IPPs for a portion of i t s e l e c t r i c i t y supply requirements. Cost e f f e c t i v e independent power production should allow d e f e r r a l of larger, p o t e n t i a l l y more expensive projects on the integrated system." "Independent Power Production i s defined as e l e c t r i c i t y generated by an independent or privately-owned f a c i l i t y , which i s connected to the BCH system." "To pursue e l e c t r i c i t y purchases and a s s i s t IPPs, BCH w i l l (among other things): - expedite the process of reaching an agreement for the purchase of e l e c t r i c i t y ; - consider special arrangements f o r projects demonstrating new technology or promising s i g n i f i c a n t environmental, s o c i a l or economic benefit to the Province." "For projects less than 5 MW, BCH w i l l i n v i t e proposals for the supply of e l e c t r i c i t y as new generation i s required i n the spring of each year for a predetermined maximum t o t a l . " P olicy Highlights: - to minimize administration and transaction costs and to f a c i l i t a t e the development of independent power projects under 5 MW capacity, standard conditions including the purchase p r i c e w i l l apply; t h i s rate w i l l be announced by BCH at the time of the RFP issue and w i l l be subject to escalation 102 - the purchase price w i l l be set annually at a value that r e f l e c t s BCH's incremental cost of e l e c t r i c i t y . - a purchase agreement w i l l be entered into on a f i r s t come, f i r s t serve basis u n t i l the aggregate of the agreement i s approximately the predetermined maximum t o t a l - BCH w i l l supply information on transmission c i r c u i t s i n the proximity of the proposed project and preliminary estimate of connection costs - BCH would prefer projects capable of supplying more than 50% of t h e i r t o t a l annual energy d e l i v e r y i n the months of November to A p r i l - proposed projects are expected to be i n - s e r v i c e within 2 years a f t e r the purchase agreement i s signed Application Procedure - proposals are f i r s t checked for completeness and registered for f i r s t come/first served consideration - proposals are given a Technical Review: proposals are reviewed for safety, protection, system compatibility, r e l i a b i l i t y , and qu a l i t y of e l e c t r i c i t y supply - i f accepted, BCH w i l l issue a Project Connection Requirements Summary and an E l e c t r i c i t y Purchase Agreement (EPA) - at t h i s point, the Project Sponsor may i n i t i a t e further discussion with BCH on either the connection requirements or the EPA; once the EPA i s signed and returned to BCH, the project i s accepted as part of the t o t a l block requirement E l e c t r i c i t y Purchase Agreement (EPA) - h i g h l i g h t s - 20 year term i n i t i a l l y , option to renew each year a f t e r , unless terminated upon 6 months notice by e i t h e r party - the project i s required to provide a minimum amount of kWh per year - BCH may terminate the agreement without notice i f proposed in-service date i s not achieved - the purchase rate i s currently 3 cents/kWh fo r f i r s t year, plus adjustments each year = CPI for Vancouver, but not exceeding +3%/yr - to q u a l i f y for a EPA with BCH, the IPP must be w i l l i n g and able to (among other things): 103 1) Demonstrate, through previous experience and/or performance guarantees, an a b i l i t y to design, finance, construct, and operate the proposed project; BCH w i l l engage independent f i n a n c i a l services to assess the c r e d i t worthiness and f i n a n c i a l state of the IPP, and to analyze the benefits to BCH of the proposed project 2) Meet the standards for e l e c t r i c i t y q u a l i t y , r e l i a b i l i t y of supply, and safety, and be compatible with the BCH system 3) Pay f o r interconnection costs and required modifications to e x i s t i n g BCH f a c i l i t i e s 4) Pay fee(s) to BCH to a s s i s t i n defraying i t s costs of evaluating the proposal 5) Obtain a l l necessary approvals, licences, and permits necessary and s u f f i c i e n t for the construction and operation of h i s plant and to comply with a l l regulatory requirements including a l l exemptions or approvals under the B.C. U t i l i t i e s Commission Act 6) Prove the land i s available for the proposed use Projects Greater than 5 MW - Major Differences and Features - proposals w i l l be c a l l e d , as required, f o r purchases of e l e c t r i c i t y for the integrated system from projects greater than 5 MW through a public RFP process; BCH w i l l purchase e l e c t r i c i t y from these projects provided that the q u a l i t y i s acceptable and the cost to BCH i s lower than the cost of other a l t e r n a t i v e s available - the e l e c t r i c i t y purchase price and other conditions for these projects w i l l be negotiated and BCH w i l l seek f i n a n c i a l arrangements which optimize benefits to BCH and i t s ratepayers - BCH w i l l consider alternative p r i c e structures and/or financing arrangements, with appropriate guarantees, to a s s i s t developments greater than 5 MW supplying the integrated system - BCH intends to issue RFPs for blocks of firm e l e c t r i c i t y supply and load displacement as required (usually i n the f a l l ) - BCH w i l l commence negotiations with the p o t e n t i a l suppliers that submit the best proposals Competitive Negotiation Process: - p r i c e i s important, but there are other key factors to be considered 104 process i s i t e r a t i v e ; i n i t i a l screening w i l l e s t a b l i s h preferred candidates on a short l i s t , on the basis of f i n a n c i a l v i a b i l i t y , technical merit, the candidate's q u a l i f i c a t i o n s , and the quantity of e l e c t r i c i t y being offered, as well as price - simultaneous negotiations w i l l then commence with those on the short l i s t to further r e f i n e and adjust the proposals, and to develop a mutually acceptable p r i c e and contract between the IPP and BCH - where there i s no agreement on pr i c e , the IPP w i l l be dropped from the short l i s t , and the next most meritorious IPP, not on the short l i s t , w i l l be admitted into the competitive negotiation process t h i s process w i l l continue u n t i l BCH enters into an agreement to purchase the required amount of e l e c t r i c i t y and/or load displacement at acceptable p r i c e s and under s a t i s f a c t o r y conditions Purchase Price and Financing Arrangements - the intent i s to negotiate a price that provides the lowest cost to BCH ratepayers and r e f l e c t s the values of firm and secondary energy - Factors a f f e c t i n g price include: - dependability of annual energy d e l i v e r i e s - r e l i a b i l i t y of supply - duration of supply - d i s p a t c h a b i l i t y - impact on the transmission and d i s t r i b u t i o n system, e.g., proximity to the Lower Mainland - BCH may negotiate financing arrangements that are of benefit to both the respondent and BCH; the purpose i s to make the project economic and financeable f o r the respondent without imposing undue r i s k on BCH - financing arrangements w i l l be evaluated on a present worth basis and would be acceptable only i f they cause no reduction i n BCH's net benefit from the project - preference w i l l be given to projects e n t a i l i n g the least amount of f i n a n c i a l and operational r i s k to BCH; performance guarantees may be required to reduce r i s k to BCH, both front-end and operational r i s k Source: A l l information taken from B.C. Hydro's "Purchase of E l e c t r i c i t y (Projects Under 5 MW) f o r B.C. Hydro's Integrated System" (May 1989), "Purchase of E l e c t r i c i t y and Load Displacement for the Integrated System from Projects Greater than 5 MW and Projects Under 5 MW" (December 1988). 105 APPENDIX 5 ENERGY COSTS OF SITE C The energy costs of B.C. Hydro's S i t e C hydroelectric project used i n Table 3 and Figures 4 . 2 to 4 . 5 were calculated as shown below. A l l data was taken from B.C. Hydro's reports e n t i t l e d "1989 20 Year Resource Plan" (A p r i l 1989), "Value of E l e c t r i c i t y " (August 1989), and "Guidelines f o r P r i c i n g of Resource Acquisitions" (November 1989). Figures are i n m i l l i o n s of d o l l a r s unless noted otherwise. A. Discount and I n f l a t i o n Rates: Nominal Discount Rate, r = 12.85% Net Discount Rate, r* =8.0% General Annual I n f l a t i o n Rate, i =4.5% Annual I n f l a t i o n Rate of E l e c t r i c i t y , e = 3.0% (1989-1998) =4.5% (1999 onwards) I n f l a t i o n Rate, 1988 to 1989 = 5.0% B. Assumptions: - S i t e C comes on-line i n 1999 a f t e r 7 year construction period beginning i n 1992; Project L i f e = 70 years. - Annual Fixed Costs escalate at general rate of i n f l a t i o n . - Annual Variable Costs (Water Rental Rates) escalate at same rate as price of e l e c t r i c i t y . - Project operates at f u l l capacity f i r s t year of operation. - Construction Costs are a series of equal annual payments and project i s 100% debt financed. - Annual Fixed, Variable, and Construction Costs are incurred at year end and do not escalate with i n f l a t i o n during the year, i . e . , fixed annual costs of $33 M i n 1989 are incurred at year end 1989 at $33 M, not 33 x 1.045 = $34.5 M. C. Costs i n 1989 Dollars: 1) Ca p i t a l Costs = $1,826.0 - includes transmission cost but not i n t e r e s t and i n f l a t i o n during construction and corporate overhead. 2) Corporate Overhead (@ 3% of Capital Cost) = $54.8 3) Total Capital Cost = 1826.0 + 54.8 = $1,880.7 106 4) Annual Fixed Cost (@ 1.81% of Capital Cost) = $33.0 - includes operation and maintenance, administration, grants and taxes, and interim replacement. 5) Annual Variable Costs (@ 0.4 cents/kWh) = $18.8 consists of energy portion of water r e n t a l fees, average annual energy output = 4710 GWh. D. Calculation of Construction Costs : 6) Present Value of Annuity, discounted at r*, over 7 years, (P/A, r*, N=7) = 5.2081 7) Annual Construction Cost = 1880.7/7 = $268.7 8) Total Capital Cost including i n t e r e s t and i n f l a t i o n at end of 7 year construction period = 268.7 x (P/A, r*, N=7)/(l+i) x (1+i) 7 = 268.7 X (5.2081/1.045) X (1.1285) 7 = $3,121.0 9) Total Capital Cost i n 1989 d o l l a r s = 3121.0/(l+i) 7 = 3121.0/(1.045) 7 = $2,293.4 10) Total Capital Cost in 1999 Dollars = $3,561.6 Note: This figure compares to figures reported i n various newspaper reports of $3.0 to $3.5 b i l l i o n f or S i t e C. E. Adjustment of Annual Variable Costs : 11) Annual Variable Costs i n 1999 Dollars = 18.8 x (1+e) 9 x (1+i) = 18.8 X (1.03) 9 X (1.045) = $25.7 12) Adjusted Annual Variable Costs i n 1989 Dollars - t h i s figure now can be escalated at j u s t the general rate of i n f l a t i o n for ease of c a l c u l a t i o n . = 2 5 . 7 / ( l + i ) 1 0 = 25.7/(1.045) 1 0 = $16.5 F. Calculation of Levelized Unit Energy Cost 13) Present Value of Annuity, discounted at r*, over 70 years, (P/A, r*, N=70) = 12.4574 14) Levelized Annual Cost = 33.0+16.5+[2293.4 X (l+i)/(P/A, r*, N=70)] = $241.9 107 15) Levelized Unit Energy Cost = 241.9 x 100/4710 =5.14 cents/kWh G. Adjustment of Capital Costs B.C. Hydro states t h e i r l e v e l i z e d u n i t energy cost for S i t e C as 4.71 cents/kWh in 1989 d o l l a r s , lower than the figure of 5.14 that I calculated above. I have assumed much of the difference between the two figures can be a t t r i b u t e d to the c a l c u l a t i o n of i n t e r e s t and i n f l a t i o n during construction as t h i s i s where most of the uncertainty i n my c a l c u l a t i o n s l i e s . I have adjusted the Total Capital Costs as follows i n order that the unit energy cost i s equal to 4.71 cents/kWh. 16) Net Present Value of 4.71 cents/kWh = 4.71 x 4710/100 x (P/A, r*, N=70)/(l+i) = 4.71 X 4710/100 X (12.4574/1.045) 17) Total Capital Cost i n 1989 Dollars = 2644.5 - (33.0+16.5) X (12.4574/1.045) Note: This figure i s equivalent to $3.2 d o l l a r s , s t i l l within the reported $3.0 range. H. Summary of Total Costs i n 1989 Dollars: Total Capital Costs = $2,053.4 Annual Fixed Costs = $33.0 Annual Variable Costs = $16.5 Levelized Unit Energy Cost = 4.71 cents/kWh = $2,644.5 = $2,053.4 b i l l i o n i n 1999 to $3.5 b i l l i o n 108 A P P E N D I X 6 P R I C E A D J U S T M E N T F O R F I R M E N E R G Y An adjustment to the rate schedule for firmness of power could done i n one of two ways: 1) using two power rates: one for firm energy and another for secondary; 2) adjusting the rate for a l l power. This adjustment could be related to the firmness (or capacity factor) of the avoided plant. For S i t e C, firm annual energy i s about 60% of i t s maximum possible output, and 97% of i t s average annual output. The minimum monthly firmness factor or the minimum annual factor could be used. Sigma defined a "firmness factor" as the expected annual energy production of a plant divided by the maximum possible production ( i n s t a l l e d capacity i n kW x 8760 hours/year), and t h i s factor can be estimated for any given s i t e (Sigma's Figure 5.3, reproduced here, shows estimated firmness factors for d i f f e r e n t regions in the province). The firmness factor would be numerically equal to the load f a c t o r f o r s i t e s supplying power to an unlimited demand such as supplying to the integrated g r i d . The system load f a c t o r may be substituted for the firmness factor for o f f - g r i d s i t e s with l i m i t e d load when the plant output i s l i m i t e d by lack of water or lack of power demand. In general, the firmness factor i s higher for coastal s i t e s (average value of 0.6) than f o r the i n t e r i o r s i t e s (average value of 0.5). Ontario Hydro uses a monthly "capacity factor", which i s determined by d i v i d i n g the t o t a l kWh delivered i n a month by the maximum possible monthly production (maximum monthly kW delivered x the number of hours i n the month). Projects with a capacity factor of 65% or more receive f u l l avoided costs while projects with less than 65% receive a rate based on the short term incremental energy costs (see Appendix 2). The Alberta Small Power Inquiry suggested those projects which cannot provide firm power should have t h e i r capacity prorated downward in accordance with t h e i r expected capacity factor r e l a t i v e to a standard capacity factor (in t h e i r case the capacity factor of the avoided proxy u n i t ) . Some factors to consider include: the long term l e v e l i z e d value of energy i s 4.5 cents/kWh while the value of capacity i s only 0.5 109 cents/kWh. Thus small producers should not be excessively penalized for providing mostly energy value, and at the same time i t should be recognized that some small producers w i l l have some firm capacity. - the energy production p r o f i l e (the seasonal v a r i a t i o n i n energy production) of small hydro plants should be considered when making adjustments to the base rate. For example, i n the south coast region, energy production i s greatest during the winter months when e l e c t r i c a l demand i s also generally the highest. B.C. Hydro has stated that they would prefer projects capable of supplying more than 50% of t h e i r t o t a l annual energy d e l i v e r y i n the months of November to A p r i l . Thus, south coast s i t e s should receive a s l i g h t l y higher rate. As an example of using two power rates, the minimum monthly energy output from a small hydro plant would receive the f u l l unadjusted rate based on the value of firm energy. A l l energy produced i n excess of t h i s amount would receive an adjusted rate based on secondary energy value. A l t e r n a t i v e l y , using an adjustable standard rate, a l l power produced from one project would receive the same adjusted rate. The standard rate would be adjusted based on the firm energy c a p a b i l i t y of the plant. The firm energy c a p a b i l i t y could be determined for the s p e c i f i c plant or, more simply, the average firmness capacity of the region where the project i s located (e.g., south coast, north coast, i n t e r i o r ) could be applied. If the f i r s t method was adopted, the firm energy c a p a b i l i t y of a s i t e could i n i t i a l l y be estimated based on the developer's hydrological evaluation. At the end of each year (or month), there could be an adjustment. I f minimum monthly output was greater than o r i g i n a l l y estimated, the developer would receive a bonus equal to the difference between firm and secondary energy based rates. I f , on the other hand, the minimum monthly output was less, the developer would be required to pay a penalty (deducted from the next year's payments) . B.C. Hydro could have the option to use the developers estimate for the entire contract ( i f B.C. Hydro thought the estimate was low) or use the bonus/penalty system ( i f they thought the estimate was too high) . I f t h i s option was s o l e l y B.C. Hydro's, developers would have a great incentive to accurately estimate the firm energy c a p a b i l i t i e s of t h e i r plant. The advantage of the second method l i e s i n i t s s i m p l i c i t y , which i s an important consideration when devising a purchase p o l i c y . 110 FIRMNESS FACTOR = ANNUAL ENERGY (kWh) INSTALLED CAPACITY (kw)K 8760 hrs FIRMNESS FACTORS FIGURE A6-1 : Firmness Factors Source: Sigma's "Small Hydro Resource" (1983) 111 >- t 100- o < o CD 2 NTERIOR < CC ui 2 Ul o Q Ul _J £ to 2 U. o H- 2 Ul o cc Ul Q. < CO < cc Ul $ o 0. 90- 80- 70- 60- 50- 40- 30- 20- 10- WEIGHTED AVERAGE OF ALL SITES SOUTH COAST — i 1 1 1 1 1 1 1 1 1 1 1 JAN FEB MAR APR MAY JUN JUL AUG SEP OCT NOV DEC MONTH VARIATION OF SMALL HYDRO POWER CONTRIBUTION Note: Generator installed to use mean annual flow, run of river. MEAN MONTHLY POWER OUTPUT AS A PERCENT OF INSTALLED GENERATING CAPABILITY vs. MONTH OF YEAR FIGURE A6-2 : Vari a t i o n of Small Hydro Power Output Source: Sigma's "Small Hydro Resource" (1983) 112

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