FROM POLICY TO POWER: REAL SOLUTIONS for BC Hydro
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TABLE OF CONTENTS IN T RODUC TION by Dav id Black , Pr esident of C O P E 378 B C E NERGY POLIC Y: THE NEED FOR C HANGE By M. Shaffer, 2011 POWE R S URGE: THE ROLE OF GOVERNM ENT POL I C Y I N BC EL EC TR I C I T Y R ATE I NC R EAS ES By J. Calvert and M. Cohen, 2011 B C HYDRO RATE REVIEW REPORT DEC ONSTRUC T ED By C. Fussell, 2011
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The Canadian Office and Professional Employees Union Local 378 2nd Floor, 4595 Canada Way, Burnaby, BC V5G 1J9 TEL 604-299-0378 TOLL FREE IN BC 1-800-665-6838 FAX 604-299-8211 www.cope378.ca
The future of our public power utility, BC Hydro, is intimately connected to the future of our province. For decades BC Hydro has efficiently provided clean affordable power for communities across British Columbia and for export in order to keep rates low for families. But the provincial government’s policy started to shift with the introduction of the 2002 Energy Plan. Government began pulling B.C.’s crown utility back from building new sources of electricity, leaving BC Hydro with only upgrades to existing dams and Site C, and handing the responsibility for the nearly all new power generation to independent or private power producers. In 2008 the provincial government amended the Utilities Commission Act to solidify this policy change, and to mandate the introduction of Smart Meters into every home and business in B.C. With these policy changes and since the introduction of the “Clean Energy Act” in 2010, BC Hydro has faced some of its most serious issues, which would compromise Hydro’s affordability and effectiveness and threaten the environment, workplace safety, and Hydro’s service to communities. Through 2007-2010 COPE 378 joined with labour and community partners across BC, including environmental organizations, economists, and municipal politicians in a large-scale campaign to push back against the government’s drive to open our rivers to private power projects. Nevertheless, many of these independent power projects have forged ahead. BC Hydro’s challenges came to a head in late 2010, as the utility announced it intended to raise residential electricity rates by almost 30% over three years. With a potential election looming, the government ordered a rate review. But instead of seeking out an arms length, impartial panel who would examine the government’s own policies, Premier Clark chose a panel of three Deputy Ministers from within government. When the Rate Review Report was released in August 2011, it found that the cost of private power projects to British Columbians had been higher even on average than the cost of importing electricity from another area if needed. However, the panel failed to make any strong recommendations on IPPs. The panel also failed to analyze the $1 billion Smart Meter Initiative. What the panel did recommend was cutting 1,000 jobs at BC Hydro, on top of the over 800 Meter Readers and other workers at Accenture slated to lose their jobs as a result of Smart Meters and changing contracts. However, their
recommendations for job cuts were based on comparing today’s workforce numbers with an artificially low year (2006), and comparing the utility with the Ministry of Transportation instead of utilities in other jurisdictions. It soon became clear that there were expert perspectives not included in the BC Hydro Rate Review Report. In order to ensure these perspectives are heard and that the government and BC Hydro can make the changes needed for the future of our public utility, we have compiled this alternative rate review report. Inside you will hear from people who are experts in their fields: First, SFU Economist Dr. Marvin Shaffer argues a change in government policy at BC Hydro is required to remove the self-sufficiency and insurance guidelines that force BC Hydro to purchase expensive and unneeded energy from private power producers. His report details recommendations to restore independent oversight of BC Hydro and to restore BC Hydro’s responsibility to meet British Columbia’s electricity requirements in a reliable, cost-effective and environmentally and socially responsible way. Second, John Calvert and Marjorie Griffin Cohen have co-authored a paper analyzing three main policy initiatives since 2002 that have dramatically impacted BC Hydro and the provision of electricity in BC. Calvert and Cohen contend the BC Hydro panel report was a missed opportunity to look at the real cost-drivers behind the application for a rate increase. Calvert is a political scientist and author of Liquid Gold: Energy Privatization in British Columbia. Cohen is a professor of public policy and a former board member at BC Hydro and BC Powerex. Finally, Colin Fussell, formerly a regulatory manager at BC Hydro and expert witness at the BC Utilities Commission, outlines why many of the Hydro report’s recommendations are unrealistic, taking a point-by-point review of the initial report’s conclusions. It is my hope that BC Hydro and the BC government will carefully review the conclusions of this alternate rate review in order to make the best decisions for the future of our public utility, and our province.
David Black, COPE 378 President
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B C E N E RGY POL ICY: T HE N EED FOR C HANGE
By M. Shaffer, 2011 power.indd 4
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With its 2007 Energy Plan and the detailed provisions imposed in the 2010 Clean Energy Act, the provincial government abandoned the traditional mandate for BC Hydro, namely to meet British Columbia’s electricity requirements in a reliable, cost effective, and environmentally and socially responsible way. Most notably, the requirement for self-sufficiency and insurance and the legislated direction to aggregate private power
SELF-SUFFICIENCY AND INSURANCE In a hydroelectric system, a key issue in ensuring a reliable supply of electricity over the course of the year is to be able to manage the risk of low water conditions. The provincial government’s self-sufficiency requirement dictates that this be done by BC Hydro acquiring or developing long term firm supply of electricity from domestic sources – a firm supply that BC Hydro could use to meet its electricity requirements when its own hydroelectric output is constrained by low water conditions. In determining the amount of power BC Hydro must acquire or develop,
for export have a different underlying objective, as explained below. Those measures, plus the heritage (average cost) pricing policy that is effectively subsidizing new electric intensive industry with rates less than half the cost of new supply, are adversely affecting BC Hydro customers and dissipating the value of BC Hydro’s unique and extraordinarily valuable hydroelectric assets. A change in policy is required.
the government legislated that BC Hydro must assume it cannot rely on the Burrard natural gas-fired thermal power plant, even in drought years. It also stated that BC Hydro must assume it cannot use the government’s entitlement to the downstream benefits under the Columbia River Treaty, a large amount of energy that is returned to the province each year (at least until 2024) and managed by BC Hydro’s trading subsidiary Powerex. The provincial government’s insurance provision dictates that by 2020, BC Hydro must acquire or develop an additional 3000 gigawatt hours (GWh) of long term firm domestic electricity supply in excess of what self-sufficiency itself would require.
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Self-sufficiency and insurance are not in fact needed to ensure reliability; nor are they cost-effective measures; nor are they environmentally responsible in all respects. Self-sufficiency and insurance are not needed for reliability. Not only do these policy measures force BC Hydro to ignore the back-up potential of the Burrard Thermal plant (which the BC Utilities Commission concluded could provide up to 5000 GWh in a dry water year) or of the government-owned downstream benefits (another 4000 GWh), but also they rule out any reliance on seasonal surplus or off-peak spot market purchases of power even though Powerex buys large amounts of that power on a regular basis for trading purposes. Annual gross imports have exceeded 10000 GWh in the last few years. In the past BC Hydro recognized, with the approval of the BC Utilities Commission and support from all consumer groups, both the back-up potential of Burrard and its ability to import spot market power in calculating how much firm supply it needs to acquire or develop to ensure a reliable supply. There is no reliability reason why that well-proven and widely supported practice could not continue. Self-sufficiency and insurance are not cost-effective. The very fact these measures had to be legislated indicates that BC Hydro would not otherwise do what the legislation requires, nor would the BC Utilities Commission approve it. To suggest they are costeffective is to say that the BC Hydro management and Board and the Commission do not know what will best serve customer interests.
much more expensive than the alternative of relying on spot market purchases when required. What spot market prices will actually be in the future is ultimately a market call. Self-sufficiency and insurance is a market call to lockin. The cost-effectiveness issue is whether that is a good market call – not simply whether it makes sense to lock-in, but also at what price and when. The cost-effectiveness of locking in is what BC Hydro and Powerex experts would normally consider, and the BC Utilities Commission would review. However, the requirement for self-sufficiency and insurance precludes such consideration and oversight. The market call is simply made in the legislation regardless of current long term firm prices, forecast spot market prices and other relevant information.
SELF-SUFFICIENCY AND INSURANCE ARE NOT COST-EFFECTIVE. THE VERY FACT THESE MEASURES HAD TO BE LEGISLATED INDICATES THAT BC HYDRO WOULD NOT OTHERWISE DO WHAT THE LEGISLATION REQUIRES, NOR WOULD THE BC UTILITIES COMMISSION APPROVE IT.
One can create scenarios where it would be cost-effective to acquire long term firm supplies to manage the risk of low water. If wholesale spot market prices were to rise high enough, then the fixed prices in long term firm supply contracts would compare favourably with the spot market prices BC Hydro would otherwise pay to import power in low water years. However, that is not what BC Hydro nor any private developer is forecasting at this time. BC Hydro forecasts and system simulations consistently show self-sufficiency and insurance to be
Supporters of this government policy argue that even if there is a net cost, self-sufficiency and insurance are beneficial because they protect ratepayers from the spot market price spikes that can occur because of combinations of unanticipated adverse events (e.g., plant breakdowns, higher than forecast demand, widespread sustained low water conditions). They cite, for example, the California energy crisis of 2001, when spot market prices reached $1000 per megawatt hour (as compared to an average $50 or less in recent years).
The 2001 experience is interesting to consider because what it clearly shows is that the best protection against such price spikes is to maintain and enhance the flexibility of BC Hydro system to import and store energy at off-peak periods and then resell energy at peak periods. BC Hydro was a net importer of power in 2001. Net imports were more than 3000 GWh that year. However, despite the unprecedentedly high prices BC Hydro paid for that power, Powerex’s trading operations enabled BC Hydro to earn record profits – over $1.5 billion. As prices rise, typically the spreads between off-peak and peak periods do as well. That is why as long as BC Hydro maintains the system
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flexibility to buy spot market power when prices are relatively low and sell when they are relatively high, prices spikes can be more of an opportunity more than a risk. A major problem with self-sufficiency and insurance is that they diminish BC Hydro’s system flexibility and trading opportunities because of the take-or-pay commitments BC Hydro enters into and the seasonal and intermittent nature of much of the supply it is acquiring. Rather than a benefit in relation to the possibility of price spikes, self-sufficiency and insurance can impose a significant cost. Finally, while some argue self-sufficiency and insurance are needed for environmental reasons, there is in fact no clear environmental case. The environmental argument in favour of self-sufficiency and insurance is that it will cause the development of more clean sources of power generation in B.C. thereby reducing the greenhouse gas emissions that would otherwise be generated by thermal sources of power. Supporters commonly state that to rely on spot market power when and if required to meet BC requirements is to rely on coal-fired electricity in neighbouring jurisdictions. With respect to this environmental argument, it is important to recognize the following: • There is no reason to believe that self-sufficiency and insurance would significantly affect GHG emissions in B.C., or have any material impact on B.C’s ability to meet its own GHG emission reduction targets. Even if BC Hydro were allowed to recognize the back-up capability of the Burrard Thermal plant it would seldom operate that plant to make up for low water conditions. Spot market purchases are generally less expensive than operating Burrard. • The spot market power BC Hydro typically imports is not ‘coal-fired’ generation. Almost half of the spot market power BC Hydro and Powerex currently import is hydro-electric power in the U.S. Pacific Northwest, purchased during the spring run-off when prices are low because of the surplus generation in that time period. The balance of the spot market imports is most likely natural gas-fired. FERC reports that natural gas (and hydro) are the marginal sources of generation in the U.S. northwest. Coal-fired generation is limited in that region and largely committed to long term supply contracts with U.S. utilities. As for Alberta, it is a net importer, not net exporter to B.C. and will likely to continue to be so because of the rapidly growing demand for electricity there.
• While there are GHG benefits from reducing the demand for natural gas-fired generation in the U.S., they would be less than for coalfired generation. In any event, it is not clear that BC Hydro has an environmental responsibility to reduce GHG emissions in the U.S., nor is it reasonable to ask BC Hydro ratepayers to pay for that. • What is a clear environmental responsibility for BC Hydro is to minimize its impacts on British Columbia terrestrial and aquatic environments. That is something that self-sufficiency and insurance do not do. They cause more development of generating plants, transmission lines, road access and other related facilities in highly valued natural environments than is needed to cost-effectively meet BC Hydro’s electricity requirements. It is interesting that among the most vocal opponents of self-sufficiency and insurance are environmentalists concerned about the development impacts they are unnecessarily causing.
In summary, there is no reliability, cost-effectiveness or unambiguous environmental case for self-sufficiency and insurance. Rather, the rationale, to the extent there is there is one, is the power project development it supports. These policy measures in fact constitute a strategy to force the development of more power projects in the province than BC Hydro needs or could otherwise justify. The question is whether this is the best way to promote economic development. Some supporters liken this economic development strategy to the two-river hydro policy that W.A.C. Bennett implemented some 50 years ago – a policy that in hindsight was greatly beneficial to B.C. There are, however, major differences between what was done then and what is being done now. One major difference is that the power projects Bennett developed are owned by BC Hydro, thereby providing benefits to the public for as long as the hydroelectric assets continue to operate. Much of the power being developed as a result of self-sufficiency and insurance are privately owned, with no comparable long-term rights to the benefits they may offer beyond initial contract periods.
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Self-sufficiency and insurance are more of a classic protectionist measure than a repeat of the Bennett tworiver policy leading to the development of the Peace and Columbia River hydroelectric systems. And, like other protectionist measures, they are paid for by customers and adversely affect disposable incomes and economic development in other sectors. There is a superficial appeal to protectionist measures to promote local economic development. But that appeal ignores the opportunity costs – what is lost as a result of higher than necessary costs. Ultimately, the economic development strategy underlying self-sufficiency and insurance is antithetical to the logic and benefits from trade.
AGGREGATING PRIVATE POWER FOR EXPORT Included in the 2010 Clean Energy Act were provisions requiring BC Hydro to seek out opportunities to buy and aggregate private sources of power for export, with BC Hydro acquiring and providing the transmission, back-up, shaping and other ancillary services needed to produce a marketable product. Just as self-sufficiency and insurance were not required or consistent with BC Hydro’s traditional mandate to meet its electricity requirements in a reliable, cost-effective and environmentally and socially responsible
way, this export policy was not designed to ensure BC Hydro maximizes the value of its hydroelectric assets for the benefit of its customers and the general public.
There is nothing inherently wrong with BC Hydro acquiring new power supply for export. The issue is whether the export price it can receive will justify the costs (and impacts) that will be incurred. The problem with the export direction in the Clean Energy Act is that it does not recognize the full costs that BC Hydro would have to incur to acquire, aggregate and export B.C. electricity supply. In particular it does not recognize the value – the opportunity cost – of the back-up, shaping and other services BC Hydro would have to provide from it hydroelectric system. The BC Hydro system is unique in its ability to provide back-up, storage, shaping and other critically important and increasingly valuable services. The demand for these services is growing throughout western North America because of the seasonal pattern and intermittent nature of much of the new sources of energy that are being developed. What must be recognized in any export strategy is that the services devoted to aggregating power for export from B.C. diminish the amount of those services that could otherwise be sold. In other words, the export of the aggregated energy supply would come at the expense of the potential export of very valuable services. The Clean Energy Act does not appear to recognize that. There is no provision requiring that the exports BC Hydro pursues under the Act must offer a return sufficient to offset the value of the services it could otherwise sell. Yet
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that is what is required to ensure BC Hydro maximizes the value of its hydroelectric resources for the benefit of British Columbians. Again, the objective underlying this policy would appear to be to support the development of more power projects than would otherwise take place. In this case the power project development would be supported by the provision of BC Hydro services without regard to their opportunity cost. The effect however is the same as with self-sufficiency and insurance. BC Hydro, its customers and B.C. taxpayers would be subsidizing the development that takes place.
fact have. The heritage supply which keeps average costs so low is already fully committed. New demands for power require new sources of supply and new sources of supply are expensive. The heritage (average cost) pricing policy is forcing existing customers to subsidize major new electricintensive industrial growth. The rationale for this policy too is the economic development it generates – in this case both electric-intensive industry and more power project development than would otherwise take place. However, again one must ask whether this subsidized economic development strategy is in the public interest. It certainly is not in the best interest of BC Hydro and its existing customers.
HERITAGE (AVERAGE COST) PRICING Government policy and legislation require BC Hydro to set its rates for all new as well as existing customers based on its historic average costs of supply. The government decided, despite the recommendations of its own Energy Task Force in 2002, to use the benefits of BC Hydro’s ‘heritage supply’ – the low cost hydro-electric and other facilities built many years ago – to keep rates low. The economic problem with this is that the low average cost rates attract new electric intensive loads that impose costs on BC Hydro far in excess of the revenues the rates generate. As the Energy Task Force concluded back in 2002, it encourages inefficient, effectively subsidized demands for power from BC Hydro. The new liquefied natural gas (LNG) facilities proposed for Kitimat and elsewhere illustrate clearly the major problem this gives rise to. The first phase of the Kitimat LNG project will reportedly consume 1.5 million megawatt hours (MWh) of electricity per year. Under BC Hydro’s average cost rates, the LNG plant will pay less than $40/MWh for this power even though BC Hydro will incur costs of $100/MWh or more to acquire new sources of supply required to meet this load. In other words, BC Hydro will lose over $60/MWh for each megawatt hour it sells. For just this first phase of the Kitimat LNG plant the financial loss for BC Hydro will total over $90 million dollars per year – a loss that other customers will have to pay for with higher rates. The basic problem is that the low average cost-based rates offer cheap power to new loads like the Kitimat LNG plant that BC Hydro does not in
AN ALTERNATIVE APPROACH Economic development is an important objective of government. However, there are far better ways to promote economic development for the benefit of all British Columbians than forcing BC Hydro: (i) to acquire more power supply than it needs or can profitably sell; (ii) to arrange and support private power export sales regardless of the opportunity cost of the services it must provide to make those sales possible; and (iii) to subsidize new electric-intensive industrial development with rates less than half the cost of the new supply that development requires. The economic development supported by those policies diminishes rather than enhances the benefits that British Columbians derive from BC Hydro hydroelectric system. An alternative approach is to do the exact opposite – build on the unique and very valuable capabilities BC Hydro has rather than dissipate that value for the benefit of private power project developers and new large energy users. A key principle underlying the maximization of social benefits is comparative advantage. You should not try to match what everyone else is doing; rather you should concentrate on what you can do comparatively best. In British Columbia, we know what that is: providing the firm capacity, shaping, storage and back-up services that is increasingly needed throughout western North America with the development of ever
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increasing amounts of wind and other intermittent sources of electricity supply. That suggests that what we should want BC Hydro to invest in are those facilities that enhance the amount and value of the services it can provide. That would include, for example, investing in: • additional dependable peak generating capacity at Mica and Revelstoke; • increased transmission capacity between BC and Alberta, and BC and the US Northwest; • firm dispatchable energy (like Site C for example) that adds to, rather than diminishes BC Hydro’s capability to provide the very valuable energy services that the market increasingly needs. Of course British Columbia should be open to the development of its own wind and other such renewable energy resources, but only where it is economic and can add value, not be dependent on artificial requirements imposed on BC Hydro for the back-up, storage and shaping services the BC Hydro system can provide at a price below their opportunity cost As for growing energy needs, certainly BC Hydro will have to acquire or develop more domestic resources as the demand for electricity in the province grows. But again, the need for those resources should not be exaggerated by policy, nor should they be encouraged with rate policies that encourage excessive, subsidized growth in BC Hydro demand. In conclusion, the policy governing BC Hydro needs to be changed. The Clean Energy Act should be repealed and replaced with policy and legislation that accomplish the following: 1. The responsibility of BC Hydro to meet British Columbia’s electricity requirements in a reliable, cost-effective and environmentally and socially responsible way should be restored. Specifically, BC Hydro’s ability to manage the risk of low water conditions in the best possible way needs to be restored.
2. BC Hydro should be allowed to recognize the back-up capability of the Burrard Thermal plant when calculating the amount of new firm supply it needs to acquire. To address concerns about excessive reliance or use of this plant, the government should impose verifiable offset requirements (or a sufficiently high tax per MWh of electricity produced at Burrard that would be dedicated to the funding of such offsets). 3. BC Hydro should be allowed to recognize its ability to purchase and import spot market power or use the Columbia River Treaty downstream benefits when calculating the amount of new firm supply it needs to acquire. 4. BC Hydro should be encouraged to promote the export of power and services provided such exports are expected to generate revenues and other benefits that outweigh the costs, including all opportunity costs, and any adverse impacts such exports would entail. 5. BC Hydro should be encouraged to undertake investments and other initiatives that will enhance the value of the power or services it can sell, provided the incremental revenues and other benefits are expected to outweigh the costs and adverse impacts. 6. BC Hydro should be required to develop rates for new large industrial users that reflect the cost of the new supply that BC Hydro would have to acquire to meet the new user requirements. New large industrial users should be given the alternative of acquiring or developing their own electricity supply, with back-up and other services provided by BC Hydro at rates that fully recover the costs, including opportunity costs, that BC Hydro would incur in providing such services. 7. The responsibility of the BC Utilities Commission to review BC Hydro’s operations, investments and other initiatives as they may affect financial performance and rates needs to be restored.
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P OW ER SU RGE : T HE ROL E OF GOVERNMENT P O L I C Y IN B C E L E CT R ICIT Y RATE INC REAS ES
By J. Calvert and M. Cohen, 2011 power.indd 11
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INTRODUCTION In an effort to respond to negative public reaction to proposed large rate increases for electricity, the BC Liberal government initiated a review of BC Hydro. BC Hydro had submitted a request for rate increases to the BC Utilities Commission (BCUC) in November 2010. The government directive, The Clean Energy Act, which placed large new costs on BC Hydro, prompted this new request for rate increases. This filing with the BCUC was for the largest rate increases for electricity in B.C. in living memory, amounting to 55% over the years between 2011 and 2015.1 (Appendix 1) Such large rate increases ran counter to the promises that the government made when it announced major changes to the electricity system in BC.2 The 2011 Review of BC Hydro3 attempted to deflect the role of government policy in the rising costs of electricity by making the parameters for the review very narrow. It looked almost exclusively at the internal mechanisms of BC Hydro, placing the most significant items accounting for cost increases outside its terms of reference. The 1 In March 2011 the BC Hydro request was revised to three years at a 9.73% increase each year, for a cumulative increase of 32%. 2 In the 2001 election campaign, the Liberals promised that a Campbell government would “Protect BC Hydro and all of its core assets, including dams, reservoirs and power lines under public ownership” A New Era For British Columbia: A Vision for Hope and Prosperity for the Next Decade and Beyond. 3 Three Deputy Ministers headed the twenty-person team to examine BC Hydro. These were John Dyble (Deputy Minister of to the Premiere, Cabinet Secretary, and Head of the BC Public Service), Peter Miburn, (Deputy Minister of Finance), and Cheryl Wenezenki-Yolland (Deputy Minister of Advanced Education). It completed its report in June 2011 and the report was released to the public August 2011.
Review’s examination looked at two areas relating to BC Hydro: these were the effectiveness of its governance framework and its financial performance. The Review concluded that the electricity utility industry worldwide is facing increasing cost pressures due to population growth and consumer demand. While it found that “BC Hydro has done a relatively good job of providing electrical service to residents of BC at low rates, BC Hydro’s operating costs have been increasing over recent years.”4 It then detailed the ways that BC Hydro could reduce cost pressures within the organization itself. Except for brief references to the problems with the government’s requirement for ‘self-sufficiency,’ there was no examination of government policy itself or the extent that its policies contributed to dramatic cost increases. Once again the deflection of government policies’ connection to the rising cost of electricity was not part of public scrutiny. This followed a consistent practice over the years of the Liberal government designing and implementing energy policy without providing avenues for public debate and scrutiny.
The following analyzes the three main government policies that radically have changed the public utility, BC Hydro, and the provision of electricity in B.C. It will show how government policy directives have a major impact on the cost of electricity for residents and affect the need for substantial rate increases long into the future.
4 A Review of BC Hydro. June 2011, p. 19.
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MAJOR POLICY INITIATIVES RELATING TO ELECTRICITY 2002 ENERGY FOR OUR FUTURE: A PLAN FOR BC 1
• BC Hydro Service delivery (administration and finance) to be contracted to private provider (Accenture) • New electricity generation to be provided primarily by the private sector • BC Hydro restricted to improvements at existing plants and Site C for new electricity generation • The use of coal-fired electricity projects encouraged • BC Hydro to adapt to US market rules to allow private energy access to transmission and to encourage private exports • Break up BC Hydro so that transmission is in a company that is distinct and separate from generation and distribution. • End Rate Freeze • Institute a temporary Heritage Contract • Allow private electricity suppliers to sell directly to industrial customers 1 Energy for Our Future: A Plan for BC, November 2002.
2007 THE BC ENERGY PLAN: A VISION FOR CLEAN ENERGY LEADERSHIP Major Features: • Require BC Hydro to acquire privately produced power to ensure energy self-sufficiency by 2016 with an additional supply of ‘insurance power’ of 3,000 GWH by 2026. • Promote small power projects through a Standing Offer Program at a set purchase price for projects up to 10 megawatts • Require BC Transmission Corporation to build transmission lines to service additional power from the private sector • Require zero greenhouse emissions from coal-fired electricity generation • Require zero greenhouse emissions from existing thermal generation plants by 2016 • Discontinue using Burrard Thermal for energy planning by 2014 • Find 50% of BC Hydro’s new energy needs through conservation by 2020 • Extend Heritage Contract in perpetuity • Begin consultations on Site C
2010 CLEAN ENERGY ACT: MAJOR FEATURES • Require self-sufficiency plus 3,000 GWh of “insurance” by 2020 • Province to become a net exporter of electricity from clean, renewable resources. • Exempt exports and major electricity projects from BCUC regulation including the following: • Northwest Transmission Line • Mica Unit 5, 6 and Revelstoke Unit 6 • Site C • Bio-energy call • Smart Meter program • Standing offer and Feed-in Tariff Programs • Clean power request for proposals • Re-integrate BC Transmission Corporation into BC Hydro • Install Smart Meters by 2012 • Activate a Feed-in Tariff Program • Use Burrard Thermal for emergency purposes only
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B.C. GOVERNMENT FRAMEWORK FOR ELECTRICITY FROM 2002 Early in its administration the Liberal government set out its plans for reshaping the electricity sector in BC in its 2002 document Energy for Our Future: A Plan for BC. This document was the foundation for the redesigned electricity sector. Up to this point BC Hydro had been primarily responsible for the generation, transmission, distribution, and services related to providing electricity in the province. This redesign broke up crucial aspects of B.C. Hydro by separating its major components. A significant part of the administration and financial functions of BC Hydro were contracted out to Accenture, a private company. The transmission system was separated from generation and distribution functions to comply with the government’s understanding of demands from the US to allow more private power access to transmission lines.1 In 2003 the BC Transmission Corporation was formed as a wholly separate company from B.C. Hydro. Both of these actions accounted for the removal of about one-third of the labour force from BC Hydro. This was costly and resulted in structural changes that ultimately proved to be inefficient. A major change was also initiated to promote a massive increase in private power production. The intent was to encourage private power companies to generate electricity for domestic use, but also for export to the U.S. To accomplish the rapid expansion of private electricity production, BC Hydro was directed to limit new generation of electricity to actions to create efficiencies on its existing facilities or through Site C, should that ever be built. BC Hydro was not allowed to invest in the new forms of ‘green’ energy that were assumed to be more environmentally-friendly than large hydro projects. Rather, BC Hydro was directed to buy its new energy requirements from private power producers (Independent Power Producers (IPPs)). The government, through this document, also encouraged the use of coal-fired power plants, noting that the abundance of coal in this province, if used for electricity, could last well over a century.2 1 The Plan specifically states that “B.C. will need to adapt to evolving market rules in the United States, if we want to continue earning the export revenues that contribute to our low power rates.” Energy for our Future, p. 6. 2 Energy for our Future, p. 14.
As might be imagined, the potential costs associated with these major changes were alarming for both the business sector and households in B.C. In order to allay these criticisms, the government instituted the “Heritage Rate” to reassure people that the low rates associated with historical hydro projects would continue for at least 10 years. As will be seen in the section dealing with rates, the costs associated with the separation (and later re-integration) of BC Transmission Corporation, and buying power from the private sector were very large and inevitably had a big impact on BC Hydro’s costs. The ‘heritage contract’ would mean little for most BC Hydro customers. Only two parts of the actions associated with Energy for Our Future were enacted through legislation and were therefore subject to debate. These were the Heritage Contract and the creation of the B.C. Transmission Corporation. The major problem with privatizing new electricity generation has been the costs for BC Hydro customers. While all new electricity costs more than that generated from older assets that largely have been paid for, the public ultimately, over time, gets the benefit from owning new assets. This is why electricity prices in BC were among the lowest in North America. However, with no acquisition of new assets, electricity prices would forever escalate with the continued reliance on purchasing private power.
The second major government document related to BC Hydro was The BC Energy Plan: A Vision for Clean Energy Leadership, which came out in 2007. The major feature of this document was the requirement for “self sufficiency” by 2016 through acquiring private “green” energy. This was an undisguised promotion of private sector power development, with the hope that the excess power that BC Hydro was required to buy could be exported to the U.S. It played on the idea of “self-sufficiency” in electricity, which most people in B.C. assumed already existed. But the government’s definition of self-sufficiency was enormously inflated – far beyond the province’s actual needs. This meant that private power developers would have to generate massive amounts of new power in order to ensure that B.C. would never, ever need to buy power on the open market. The plan also demanded “insurance” of 3000 GWh above what would be needed for self-sufficiency, even in rare, extreme drought years.
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The requirement for false “self-sufficiency” received a great deal of criticism at the time, mainly because this criterion would incur enormous unnecessary expenses for BC Hydro customers.3 It forced BC Hydro to buy high cost, and low-value run-of-river and wind energy, energy that is not reliable and is not without considerable environmental impacts.4 The encouragement of coal for electricity production in the 2002 Energy for Our Future also would have substantial environmental impacts and after considerable negative public reaction, was modified in the 2007 Plan to require zero emissions from coal-fired electricity.5 Since zero GHG emissions from coal is not possible to achieve with existing conditions, coal-fired electricity plants were essentially banned. The drive for acquiring excessive amounts of electricity was based on two major premises on the part of the government. One was the assumption that substantial revenue would be generated from the export of electricity to the U.S. This objective of both the 2002 and the 2007 energy plans was rooted in what was perceived to be the desperate need in California for electricity after the collapse of Enron and its shift to a deregulated market-based system. This was a serious miscalculation on the part of the BC government, and basing its entire energy plan on the assumption that exports to the US would generate enough money to pay for the very expensive private power it was buying was widely off the mark. The second premise was that people would accept the privatization of electricity in B.C. and the huge rate increases this would entail if these changes were sold to them as “green” energy. In many respects this 3 Marvin Shaffer & Associates, Inc. Lost in Transmission: A Comprehensive Critique of the BC Energy Plan (Vancouver: Canadian Office and Professional Employees Union Local 378, 2007). 4 See, for example, John Calvert, Liquid Gold: Energy Privatization in British Columbia (Halifax & Winnipeg: Fernwood, 2007); Margin Shaffer & Associates, Is the Energy Plan Really Green? The Supply Side: Targeting Low Value/High Cost Resources (Canadian Office and Professional Employees Union Local 378, 2007), Marjorie Griffin Cohen, “Electricity Restructuring’s Dirty Secret: The Environment,” Johnston, Josée, Michael Gismondi, and James Goodman. (Eds.) Nature’s Revenge: reclaiming sustainability in the age of corporate globalism. (Peterborough, ON: Broadview Press, 2006), pp. 73-95. 5 BC was planning to introduce coal-fired plants at a time when they were being phased out in Ontario. Two 30-year contracts were awarded for coal-fired plants as a result of BC Hydro’s 2006 Open Call for Power.These were the Princeton Power Project and Wapiti Power Development Project, but public protests led the government to demand zero emissions from coal projects, effectively killing the use of coal in B.C. See Sunny Freeman, “Power Struggle Over BC’s First CoalFired Plant, The Tyee, November 17, 2006.
was disingenuous because with the exception of Burrard Thermal, a natural gas fired plant that was not used regularly, BC Hydro’s electricity generation did not produce GHG emissions. The only potential source of GHG emissions would be from the new coal-fired plants the government proposed in its initial electricity plan in 2002 and the gas plants that account for 25% of the total IPP energy BC Hydro buys.6 The third major government policy directive occurred through the 2010 Clean Energy Act. This Act accelerated the time for BC to have “insurance” for its energy efficiency. This requirement supports the Liberal government demand that BC become a net exporter of clean energy, since BC Hydro would need to buy more private power even sooner. The Clean Energy Act exempted electricity exports and major transmission projects (most notably the expensive Northwest Transmission Line) from BCUC oversight and regulation and it also legislated the Smart Meter Program by requiring that Smart Meters be installed by 2012. The projected $930 million cost of Smart Meters also was to be exempt from BCUC examination. In fact, the exemptions from BCUC oversight were for some of the most costly features of the government’s policy directives for BC Hydro itself. In addition to exports and transmission projects, other exemptions included the Standing Offer and Feed-in Tariff programs, clean power requests for proposals, Site C, and the new units on the Mica and Revelstoke dams.7 This means that the most expensive projects in the near future will have no cost reviews by BCUC to determine their viability and value to customers.
In addition to these directives that would result in increased costs for BC Hydro, the Act also required the re-integration of the BC Transmission Corporation into BC Hydro. The artificial separation of 6 Review of BC Hydro, Figure 3.4.5, p. 107. 7 Both the Standing Offer Program and the Feed-in Tariff Program are designed to encourage small-scale private power that BC Hydro would be required to buy. The Standing Offer Program mandates that power from any clean energy private project of between .05 and 15 MW would have to be acquired by BC Hydro (BC Hydro, Standing Offer Program Rules, January 2011). The feed-in tariff program guarantees access to the BC Hydro grid from producers of electricity, including households, using any kind of ‘green’ technology. This program is not yet in operation but ways that those using renewable energy can recover their costs by selling power to BC Hydro are being developed. http://www.bchydro.com/planning_regulatory/acquiring_power/feed_in_tariff.html. Both of these programs are extremely expensive because of the cost of connecting the small projects to the grid, and the high costs per unit of electricity generated.
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the transmission system into a separate corporation that occurred as a result of the 2002 Plan proved to be as unworkable and expensive as many believed it would be. It was also unnecessary, once again indicating that the Government had seriously misinterpreted the necessity to conform to US wishes. Reintegrating the BCTC labour force into BC Hydro added to the expenses of the corporation. It also contributed to a false sense of the escalation of the size of the BC Hydro labour force, one factor that was raised as a reason for escalating operating costs in the Review of BC Hydro.
THE RECOMMENDATIONS OF THE 2011 REVIEW OF BC HYDRO The Review clearly places the blame for rising electricity prices on BC Hydro’s inability to contain costs, and as a result most of its recommendations relate to BC Hydro’s operational processes,8 capital spending, and approaches to procurement and project management.9 While it notes that the primary drivers for operational costs relate to increased maintenance on aging infrastructure and increased volume of work resulting in increased staffing levels, it nevertheless is highly critical of BC Hydro’s inability to effectively contain its costs. The Review lists a number of problems with labour costs and an escalating workforce size by comparing the 2006 levels of employment with the 2010 levels. What it fails to point out is that in 2006 BC Hydro had its lowest employment levels in more than a decade, primarily as the result of losing about one-third of its workforce, or 1,800 workers, who had been transferred to Accenture and the BCTC. It also failed to note that many of the functions of these separate corporations could not be disintegrated easily from BC Hydro so as a result, duplication of efforts occurred. This was tacitly admitted through the requirement in the 2010 Act to re-integrate BCTC into BC Hydro. These issues are
8 Costs for electricity purchase agreements with IPPs were reclassified as operating costs in 2011. 9 The Review provides 56 recommendations. Of these recommendations only two are directed at ‘the province,’ six are directed to both BC Hydro and the province and all of the rest are directed to BC Hydro.
not considered in the Review; rather, it goes with the recommendation that the current staff of 5,968 be reduced to 4,800. This means 1,186 fewer workers at BC Hydro, or about a 20% reduction in the labour force.10 The Review suggests that while this might be a challenge to the organization, it should be able to replace some of this work with contract work. The Review is not clear why this would result in any savings, however. It also faults the organization for various postretirement-related benefits, such as extended health care, and for what it considers to be excessive overtime. It also argues that BC Hydro has a “gold plated” culture of “excellence” that is unwarranted and that it has been more diligent than necessary in providing oversight on projects. Since so many of the projects that require oversight are private projects, this oversight is probably keeping BC customers from more serious consequences of privatization of electricity than already exist. The targeting of labour within BC Hydro for cost cutting is a recommendation that has the potential to jeopardize BC Hydro’s performance. Another recommendation that is also unwise relates to the treatment of capital projects to save costs. The Review notes that ‘the availability of BC Hydro’s generation facilities is declining and is not comparing favourably to Canadian Electrical Association counterparts.”11 This decrease in reliability is a result of aging assets because relatively little new investment had been made since the Revelstoke Dam was built. The result is that the aging infrastructure has forced BC Hydro to aggressively increase its capital spending program in the past five years. The Review makes many recommendations to reduce capital spending, including deferring projects, which simply pushes the cost onto future years, or maintaining less control over projects. It is this recommendation, which the Review says could be accomplished by entering into Public-Private-Partnerships that would result in the biggest changes.12 This would allow private firms to become ‘partners’ with BC Hydro in the work that a company does on BC Hydro’s assets and could give these ‘partners’ a stake in BC Hydro itself. This is a form of privatization and the more it is used, the less the utility’s assets will be owned by the province.
10 Review of BC Hydro, pp. 40-43. 11 Review of BC Hydro, p. 74. 12 Review of BC Hydro, Recommendation 30, p. 68.
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There is no doubt that some of the recommendations for cost-cutting are reasonable. It would be an unusual organization that did not have improvements to make. But on the whole, the expenses that appear to be higher than warranted (e.g., the performance bonuses for senior management and the small number of employees relative to managers), are minor compared with the enormous costs that are being incurred because of government directives to facilitate the privatization of new electricity production in B.C. The only slight nod in this direction is the admission in the report that the Government’s “policies governing electricity, which focus on clean energy and self-sufficiency, were developed in an environment different from today’s economic context. Greater flexibility may be required…”13 The Review specifically recommends that the province and BC Hydro review both the definition and the timelines for ‘self-sufficiency’ in order to make it sustainable for the long-term.14 While the Review is firm in its directives to BC Hydro, it is rather vague in the recommendations regarding government policy. As a result, there are no specific recommendations about either what ‘selfsufficiency’ should mean, or how long B.C. Hydro will have to achieve it. The Review gives BC Hydro the option to reduce the three-year rate increases from 32.1% to either 18.9% or 16.6%.15 These would be achieved through short-term cost reductions and would clearly take the government beyond the next election. The short-term nature of the solutions does not begin to deal with the serious cost problems that have been imposed on BC Hydro. But other than the recommendation to review the timetable and definition of self-sufficiency, the other major government cost drivers were not identified as issues that need to be fixed.
THE REVIEW’S EXPLANATIONS FOR BC HYDRO’S PROPOSED RATE INCREASES ARE INADEQUATE While the recent Review pointed the finger at BC Hydro management for much of the increase in rates, both the government and BC Hydro previously had been arguing that the most important factor for rising 13 Review of BC Hydro, p. 21. 14 Review of BC Hydro, Recommendation 46, p. 93. 15 Review of BC Hydro, p. 21.
costs is related to BC Hydro’s large capital investment program. In its F20012 – F2014 Revenue Requirement Application last fall to the BCUC, BC Hydro maintained that a major reason for the proposed expenditure increases lay in the utility’s need to upgrade major components of its aging facilities, including installing new turbines in several dams, modernizing its high voltage transmission lines to the lower mainland and investing in other aspects of its infrastructure, as well as the potential cost of Site C should it proceed. In its words: BC Hydro plans to invest approximately $6 billion over the next three years to renew, upgrade and expand capital infrastructure across the province. The largest capital projects that are planned include the Vancouver City Central Transmission Project, the Columbia Valley Transmission Project, and the Interior to Lower Mainland Transmission Project, the Northwest Transmission Line Project, the Smart Metering and Infrastructure Program, the Mica Units 5 and 6 Project, the Ruskin Dam and Powerhouse Upgrade Project, the John Hart Upgrade Project, and the Site C Clean Energy Project.16 (BC Hydro F 2-12 – F2014 Revenue Requirement Application) A list of these upgrades taken from the more recent 2011 Annual Report is in Appendix 2. Some of these major upgrades are needed and are overdue.17 New turbines in existing dams and the refurbishment of major existing transmission lines nearing the end of their service life are important investments that preserve the value of the public’s BC Hydro assets and ensure reliable service in the future.
But a significant part of BC Hydro’s capital spending is the result of government policy directives, such as the highly controversial $930 million “Smart Meter” program and the $830 million BC Hydro paid for one third of the energy of the Waneta power plant to mining giant Teck-
16 BC Hydro, F2012 to F2014 Revenue Requirements Application Executive Summary, p. 1. Submitted to the BCUC March 1. 2011. (BCUC Project No. 3698592) 17 The current Liberal government and the previous NDP government can be criticized for their failure, over the past two decades, to encourage some of the investments required to upgrade parts of the utility’s infrastructure. Both the NDP, during the 1990s, and the Liberals, during their first two terms in office, wanted to avoid raising rates. Postponing major investments was a way to do this. However, even if the current Government can make the claim that BC Hydro should have made larger capital investments during the 1990s, once it was elected in 2001 it was in a position to address this issue and has had a full decade to do so.
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Cominco.18 Additionally, BC Hydro has spent approximately $250 million on its costly initiative to carve out - and later re-integrate - the British Columbia Transmission Corporation to accommodate the demands of the private power industry to restructure BC Hydro’s operations in line with the model promoted by the US Federal Energy Regulatory Commission (FERC).19 The Crown Corporation has also had to absorb the extra costs of its outsourcing contract with Accenture, which one analyst calculated has amounted to an extra $250 million.20 To this we can add the costs of the major transmission lines, sub-stations and related facilities needed to service the rapidly expanding mining and oil and gas sectors. BC Hydro is also incurring significant costs for connecting, servicing and monitoring the increasing number of private power projects that need to connect to the main grid. While some of these costs are factored into the price it pays for private power, a significant part is absorbed in the overall administrative expenses of the utility, but it is very difficult to get a clear picture of just how much it is.
THE HIGH COST OF THE GOVERNMENT’S PRIVATE POWER POLICIES While the Review raised concerns about the Government’s “selfsufficiency” policy, it did not take the next logical step and assess the very large potential losses to BC’s ratepayers from this policy. Fortunately, it does provide some numbers which show the enormous gap between what BC Hydro is paying private power developers for their energy and the price this energy is valued at on the international energy market. In 2010, at the Mid-Columbia trading hub where BC Hydro can
18 BC Hydro (2009) “BC Hydro Plans to Purchase One Third Interest in Waneta Dam” Press Release, June 17, 2009. While the cost of the 1,000 GWh of energy it will obtain from this facility is less than what it is now paying for other private energy, there are still concerns about the price BC Hydro paid and also the fact that it remains in a minority ownership position. 19 BC Hydro estimated that it cost $65 million to carve out its transmission system in 2003. When it re-integrated the system, it claimed that the annual savings would amount to $25 million a year. Assuming this was the annual loss over the 8 year experiment, and adding the start up costs, the total amounts to slightly more than a quarter of a billion dollars. 20 Will McMartin The Tyee, June 21, 2010.
buy, or sell, energy, the wholesale electricity price ranged from $4.34 MWh to $52.43 MWh.21 The average price for the year 2010, according to the US Energy Information Administration (EIA) was $35.96.22 In contrast, the price BC Hydro paid to private power developers the same year in its energy purchase agreements was $124.00 MWh. Thus the gap between the market price and the price BC Hydro is currently paying ranges from approximately $72 MWh to just under $120 MWh. The 3,000 GWh “self sufficiency” policy will guarantee that BC Hydro will have a significant surplus of energy every year. It will have to sell this surplus energy on the market. If forced to sell, rather than spill water, it might end up getting a price somewhere in the mid to high range of the Mid-Columbia rate. Even if we use the highest figure cited by the Review ($52.53 MWh) and compare it with the price BC Hydro is paying in its recent energy purchases, ($124 MWh), we see that the loss could be roughly $71.50 for every MWh it sells. For the critical (3,000 GWh surplus), average (7,000 GWh – 8,000 GWh) and favourable (14,000 GWh) water years, this would mean that BC Hydro’s ratepayers would incur losses ranging from $214 million (critical), $500 - $572 million (average) and $1,000 million (favourable).
The annual losses could be much higher if BC Hydro were to receive a price closer to the 2010 Mid-Columbia average wholesale electricity price of $35.96 MWh.23 In reality, no one knows with certainty the exact price of energy a decade or two from now, or how much energy BC Hydro will end up selling on the market at that time. However, what the Review failed to do was to provide the public with a clearer sense of the extent to which BC Hydro’s ratepayers are financially vulnerable as a result of the Government’s buy high, sell low policy. A question that logically arises is why is it only recently that the public has begun to voice concerns about the impact of the government’s 21 Review, p. 92 22 “Plentiful Water and Low Natural Gas Prices Cut Northwest Power Prices in Half.” Today in Energy. March 4, 2011. http://www.eia.gov/todayinenergy/detail.cfm?id=370. For the current year it appears that wholesale electricity prices will be even lower. EIA data for the first half of 2011indicate a fall of 26% in the Pacific Northwest wholesale price. “Today in Energy” Aug. 4, 2011. 23 These calculations are based on the numbers provided in the Review and cited earlier, namely a 3,000 GWh surplus in low water years, a 7,000 GWh to 8,000 GWh surplus in an average year and a 14,000 GWh surplus in a high water year.
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energy policies on rates? A key reason is that the costs of these expensive contracts are not immediately felt by ratepayers. There is a significant time lag between the date a contract is signed and the date the developer completes the project and starts delivering power to BC Hydro. This can vary significantly, depending on the project, but normally is in the range of 6 to 8 years. Consequently, BC Hydro – and its ratepayers - do not start paying for the power until the utility begins to receive it. It is only now that the full impact of private power contracts signed half a decade ago, or more, are showing up in the bills of Hydro customers.
THE GROWING VOLUMES OF PRIVATE POWER One of the key drivers of the projected rate increases is that a growing volume of expensive private power is now coming on stream as a result of energy contracts signed during the past decade. The size of BC’s financial commitment to purchasing private power has risen substantially in recent years. According to its F2012 – F2014 Revenue Requirements Application to the BCUC, BC Hydro now has 110 active EPAs involving a commitment to purchase a total of 19,164 GWh of energy, annually.24 (See Appendix 3 for details) As we might expect, as the total volume of private energy has been increasing, so has the total bill. In 2003, BC Hydro spent $290 million on private power contracts.25 Since then the bill has increased substantially, with the projected cost for fiscal 2014 reaching just under $940 million as the following chart illustrates.26 (See Appendix 4 for a detailed break-down of these expenditure projections.) 24 BC Hydro, F2012 to F2014 Revenue Requirements Application. op. cit. Chapter 4 - Cost of Energy, Table 4-5 p. 4 – 17. 25 BC Hydro, Revenue Requirements Application F2004/5 - F2005/6. November 15, 2004 Compliance Filing, Schedule A-9, p. 15. 26 As we note later in this paper, the Auditor General was extremely critical of how BC Hydro reports its long term energy purchase agreements in his 2011 audit of the Province’s finances. He noted that the impact of 20 and 30 year contracts was not being adequately documented by the corporation in its published statements. Instead it only provided only short term projections of future financial impacts. The relevance of this point is that providing only short term estimates of costs lacks transparency and makes it very difficult for the public to assess the overall impact of such costs on future rates. Office of the Auditor General of BC. Report 6, September,2011: Observations on Financial Reporting: Summary Financial Statements 2010/2011. www.bcauditor. com.
19 Source: BC Hydro F2004/05 – F2005/06 and F2012 – F2014 Revenue Requirement Applications
The above table only illustrates costs up until 2014. However, many of the recently signed contracts are not yet delivering power. Most will run for between 20 and 30 years. One, with the Forrest Kerr 195 MW runof-river project, runs for 60 years. So the impact on rates will continue to escalate as more and more of this private power is delivered to BC Hydro.
THE IMPACT OF ENERGY INTENSIVE RESOURCE DEVELOPMENT In addition to rising energy costs, another major factor that is pushing up the rates of residential customers is the Government’s energy intensive resource development strategy. This strategy is forcing BC Hydro to plan for a significant increase in future energy purchases to service the rapidly expanding oil and gas sectors and the large number
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of new mines the government anticipates will be built over the next decade. The issue is not only that these industries will raise demand for new energy: it is that the price they anticipate paying for this energy is far lower than what it will cost BC Hydro to acquire it. Currently, the rate large industrial customers pay for their electricity is just over $40 MWh under the transmission rate category. As we noted earlier, the Review indicated that BC Hydro has been paying approximately $124 MWh for its new energy. While BC Hydro’s own electricity from its major dams is far cheaper, the problem is that it currently only has enough to supply its existing customers. It does not have a significant surplus that it can draw upon to meet the projected needs of these energy intensive industries in the future and the current policy framework severely limits its options. Consequently, if the government achieves its policy objective of encouraging the rapid development of new resource projects, BC Hydro will have to acquire a very large volume of new electricity.27 To the extent that these resource industries base their investment decisions on the government’s promise of cheap electricity, this will also drive up the amount of energy BC Hydro will need to acquire in the coming years. The promise of low cost electricity will affect the economics of new energy intensive projects, making investments in BC comparatively more attractive. In addition, because many of these resource projects are located in areas currently not well serviced by BC Hydro’s existing transmission system, it will also mean that BC Hydro will be making large investments in new transmission lines, sub-stations and other infrastructure, whose purpose is almost exclusively to service resource extraction projects. If the government’s resource sector strategy only involved one or two mines or a small expansion of the gas sector, this would not be a major issue. However, the number of energy intensive resource projects that are now being developed and the amount of new electricity they will need makes this a major issue, particularly as residential ratepayers will end up paying for a significant portion of its costs under the present pricing structure. Three specific types of resource projects are of particular concern: the rapidly growing natural gas sector; the construction of new LNG facilities; and, the development of a significant number of new mines. 27 This would be in addition to BC Hydro’s requirement to maintain the 3,000 GWh surplus.
THE PROJECTED ELECTRICITY DEMANDS OF SUPPLYING THE DAWSON CREEK/ CHETWYND NATURAL GAS PROJECTS The Government has enthusiastically promoted a major expansion of shale gas production in the Dawson Creek/Groundbirch/Chetwynd area of Northeastern BC. The Montney shale gas basin has one of the largest pools of accessible natural gas in North America. New horizontal drilling and multi-stage hydraulic fracturing technologies make this gas comparatively cheap to extract. BC Hydro estimates that by 2020 the Montney basin will be producing at least 3 million cubic meters of natural gas a year and possibly much more. Once extracted, the natural gas must be compressed for shipment and this requires a great deal of energy. Usually the gas itself provides this energy. But - somewhat bizarrely - the government believes that it can offset the increased GHG emissions associated with compressing gas by supplying electricity to perform this function, as well as to meet some of the other energy requirements of the gas industry. (Producing less gas would also reduce GHG emissions. But this is an option the government has rejected.)
BC Hydro’s mid-range estimate of electricity load growth for gas projects indicates that by 2027 it will need to supply 363 MW of power to customers in the Montney gas field area.28 However, if the gas sector expands more rapidly it will need even more electricity. BC Hydro’s high range estimate indicates that within a decade, it may end up supplying over 500 MW of power annually. This is roughly half the projected output of its proposed Site C dam. BC Hydro’s mid-range estimate indicates that it will need to supply an average of about 1,800 GWh of energy to the gas industry every year in the period from 2016 to 2030.29 At the current price of $124 MWh it is paying to private power developers, this translates into an average annual cost of roughly $223 million. However, if it ends up selling to
28 BC Hydro. Dawson Cree /Chetwynd Area Transmission Project (Project No. 3698640). Application for a Certificate of Public Convenience and Necessity (CPCN). British Columbia Utilities Commission (BCUC) Aug. 3, 2001. Appendix B, p. 19. http://www.bchydro.com/planning_ regulatory/regulatory.html. 29 Ibid. Appendix B, Table 1 “Expected Annual Gas Production and Electricity Demand. p. 82.
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the gas industry at the current price of roughly $40 MWh, it would only receive $72 million. This would result in an average loss to BC Hydro’s ratepayers of about $151 million every year during the period. The current transmission infrastructure supplying electricity to the Dawson Creek/Chetwynd area is not capable of handling the volume of electricity the gas fields will require in the coming years. To address this issue, BC Hydro submitted an application to the BCUC for a major upgrade to its transmission system. It estimates that it will spend $255 million between now and 2015 on this project which is needed only because of the projected expansion of the gas industry.30 However, when gas production diminishes in a little over 20 years’ time, BC Hydro’s ratepayers may end up having funded an expensive and arguably very overbuilt transmission line for which there will no longer be a major need.
LNG PROJECTS WILL REQUIRE LARGE AMOUNTS OF NEW POWER THAT BC HYDRO CURRENTLY DOES NOT HAVE Another major new energy project, the proposed $3.5 billion first phase of the Kitimat LNG terminal, will also result in a major increase 30 BC Hydro, Dawson Creek / Chetwynd Area Transmission Project ASP-2011-027.
in demand for BC Hydro’s energy. Once in operation in 2015, the project will have the ability to process 5 million metric tons of liquefied natural gas or roughly 20% of BC’s natural gas output. Although originally intended to allow imports of gas, the dramatic increase in gas production within BC has led to a reversal of the plan. It is now being built to facilitate gas exports to customers across the Pacific.31 The proponents applied to the NEB on December 9, 2010 for a 20 year export permit.
The first phase of this facility, once completed, will need 250 MW of power. It will use an estimated 1500 GWh of electricity annually. Using the same cost and price estimates as in the Dawson Creek example of the cost of new energy to BC Hydro and the sale price it will receive for this energy, ratepayers could end up losing up to $125 million for every year it is in operation.32 If the second phase proceeds, the total could double. And the NEB has received at least one other application for a new LNG export facility on the BC coast.33 Even if BC Hydro is able to source new energy that is cheaper than the 31 David Ebner, “EOG buys rest of Kitimat LNG project” Globe and Mail Aug. 24, 2010. For a description of the project see the proponent’s web site: http://www.kitimatlngfacility.com/. See also: National Energy Board Hearing Order GH-1-2011 regarding KM LNG Operating General PartnershipKitimat LNG Export Licence Application. December 9, 2010. 32 Marvin Shaffer, “A Jobs for Jobs Strategy” CCPA Policy Note Sept 23, 2011. http://www. policynote.ca/a-jobs-for-jobs-strategy/. 33 Pipeline News, “NEB Gets Another Application Proposing To Export LNG Off B.C. Coast.” March 16, 2011. http://www.pipelinenewsnorth.ca/article/20110316/PIPELINE0119/303169976/-1/ pipeline/neb-gets-another-application-proposing-to-export-lng-off-bc-coast.
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prices it is currently paying as a result of changes in the government’s electricity policies, ratepayer losses will still be very substantial unless the industrial tariff structure is fundamentally changed. New energy will still be considerably more expensive than what BC Hydro is currently planning to charge industrial customers under its current tariff. Yet in a recent media interview, Premier Christy Clark assured BC residents that BC Hydro would be able to supply the power to the first phase of the LNG project and most likely to the second as well. In her words: “We are confident, absolutely confident that phase one will be powered up - no question - with existing resources…”34
THE IMPACT OF THE RAPID EXPANSION OF POWER HUNGRY MINES Turning to the additional electricity demand in the mining sector, the government’s recently released “Canada Starts Here: The BC Jobs Plan” asserts that by 2015, eight new mines will be operational and nine existing mines will have completed major upgrades.35 The government also intends to reduce, significantly, the various regulatory requirements which it argues are unnecessarily delaying the approvals of new projects. This may mean that even more mining projects will go forward, with a corresponding increase in electricity demand over the coming decade. A study by Marvin Shaffer of the impact on BC Hydro of one proposed mine, the Prosperity Gold-Copper Mine Project, found that BC Hydro would lose heavily by supplying it with the 750 GWh of electricity it would need, annually, once in full operation. In his words: “The estimated costs to BC Hydro and its customers, plus the GHG offset costs imposed by this project total almost $38 million per year.”36 Of this total, fully $35 million was the projected loss to BC Hydro’s ratepayers. In making his calculations, Shaffer used BC Hydro’s earlier cost of purchasing private energy - $88 MWh - and BC Hydro’s slightly lower industrial rate at the time - $37.4 MWh. If we used BC Hydro’s 34 Malcolm Baxter, Kitimat Northern Sentinel Sept. 30, 2011. 35 Government of BC, Canada Starts Here: The BC Jobs Plan, Sept. 22, 2011. p. 15. 36 Marvin Shaffer and Associates, “Benefits and Costs of the Prosperity Gold-Copper Mine Project”, Report Prepared for the Friends of the Nemaiah Valley, March 11, 2009, p. 19. http:// www.fonv.ca/media/report-shaffer-prosperity.pdf
current cost of energy – roughly $124 MWh - and the current rate it charges to industrial customers of $40 MWh, the potential loss every year could be over $63 million. And this is just one mine. As with the Dawson Creek/Chetwynd transmission infrastructure, another major cost associated with mining development is transmission upgrades. BC Hydro estimates that the Northwest Transmission Line will cost $404 million to build, although this could be higher if the line is extended further north as the Federal Government has indicated it wants in return for its promise of $130 million to subsidize the project.37 BC Hydro estimates it will get some funding from the new mines, although it is not clear how large this contribution will be. Nevertheless, BC Hydro will end up paying the largest share of this project. And this means all ratepayers will end up contributing to a new transmission line whose benefits will go almost exclusively to the mining sector.38 The cumulative impact of supplying new energy to eight new mines and to another nine mines undergoing upgrades will be very substantial and will force BC Hydro to acquire a great deal more energy in the coming years. Under the current system for setting rates, the additional costs of this energy, as well as the infrastructure needed to deliver it, will be shared among all BC Hydro customers, even though the benefits will almost exclusively go to these resource projects. This means residential ratepayers will be paying a significant part of the cost of the energy that BC Hydro will be acquiring for the resource sector.
In addition, the promise of cheap – or, more accurately, heavily subsidized – electricity will not encourage conservation. Large volume electricity customers are sensitive to the price they pay for their energy. If the price is low and they believe the Government will guarantee that it will remain relatively low over the term of their projects, they will have less incentive to adopt energy saving technologies or methods
37 Pollon, Christopher, “Northwest Power Line Grows, So Does Controversy: Gov’t says extending grid beyond 2009 plan will lower greenhouse emissions. Critics see a boost to mining -- and emissions.” The Tyee. July 18, 2011. 38 The formula for determining the cost allocation for upgrades BC Hydro has to make to its transmission system from connecting new industrial customers is set out in BC Hydro’s Tariff Supplement #6. New customers are initially charged the extra costs BC Hydro incurs, but if they purchase the agreed amount of electricity over the following 8 years, the full amount is refunded to them. New customers are responsible for funding connections from their facility to the main BC Hydro grid.
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of operation.39 Arguably, the price they should pay ought to be at least what BC Hydro will be paying to supply them with new energy. If new resource projects are only viable with highly subsidized electricity, it is not clear why they should go forward in the first place and even less clear why other ratepayers should effectively subsidize them.
LACK OF TRANSPARENCY OF FINANCIAL DATA One of the most serious concerns with the recent Review of BC Hydro is its failure to comment on BC Hydro’s lack of transparency in reporting its financial obligations to the public. In a recent report, John Doyle, BC’s Auditor General, singled out both the government and the Crown utility for failing to present a clear and understandable account of the utility’s long term contractual commitments and for the increasing use of deferral and regulatory accounts.40 Doyle indicated that in the previous year’s audit he had flagged these problems but they had not been rectified.
difficult for citizens to assess their future financial implications or to determine the long term consequences on rates and on future service delivery. Consequently, he recommended that “…government provide more complete disclosure of the anticipated payments to be made after five years so that stakeholders can fully appreciate the duration and timing of these obligations.”43 Another gap in the Review is that it does not attempt to focus on ways to reduce the growth of energy demand in the province and thus reduce the amount of power BC Hydro will need to purchase. There is still considerable room to moderate the growth of demand from residential and commercial customers through conservation initiatives identified in BC Hydro’s 2007 Conservation Potential Review. And there is much more potential in the industrial sector if the government’s electricity intensive resource strategy were to be significantly modified.44
Doyle noted that the province now had over $80 billion in long term contractual commitments and that the total had increased significantly since 2010. He pointed out that “…most of the 2011 increase is due to BC Hydro entering into long-term energy purchase agreements with independent power producers.”41 In BC Hydro’s most recent Annual Report, the Crown utility includes a footnote indicating that it had outstanding commitments of $43 billion in long term purchase agreements, of which approximately $40 billion were for private power purchases.42
The Review also looked at the controversial issue of smart meters. It concluded that “(t)he business case rationale for the SMI project appears reasonable.”45 In support of this conclusion, it basically reproduces the costing rationale provided by BC Hydro (and the government) to justify the $930 million dollar price tag. However, its evaluation does not question the assumptions on which the costing has been made. Nor does it raise concerns about the haste with which the meters are being introduced.46
Doyle also complained that few of the details of these power purchase agreements were available to the public. Consequently, he felt it was
43 Office of the Auditor General, op. cit., p. 28.
39 The Clean Energy Act includes a provision that would enable BC Hydro to negotiate long term fixed price electricity sales contracts with major industrial customers. This is worrisome, as it could result in these customers locking in current prices for many years into the future in order to avoid sharing the cost of the inevitable rate increases BC Hydro will be implementing. The fact that the legislation included such a provision is troubling. The relevant provision reads as follows: “Domestic long-term sales contracts. 9: The authority must establish, in accordance with the regulations, a program to develop potential offers respecting domestic long-term sales contracts for availability to prescribed classes of customers on prescribed terms, including terms respecting price, for prescribed volumes of energy over prescribed periods.” 40 Office of the Auditor General, “Report 6: Observations on Financial Reporting: Summary Financial Statements 2010-11”.Victoria: Sept. 2011. 41 Office of the Auditor General, 2011. ibid. p. 28. 42 BC Hydro. Annual Report, 2011.Note 16:Commitments and Contingencies , p. 80,
44 BC Hydro has introduced ‘stepped rates’ for transmission rate (1823) customers who use large volumes of energy. The lower rate which applies to the first 90% of a customer’s bill is currently $33.53 MWh plus a small demand charge. The remaining 10% is charged at a rate of $73.6 MWh plus the demand charge. But there are also special tariffs for Time of Use Customers and for use during different seasons. The average is now about $40 MWh, but may vary significantly from one customer to another. However, thus far the ‘stepped rates’ do not appear to have had a major impact on increasing the average cost per MWh of the electricity BC Hydro is selling to large industrial customers. 45 The Review, pp. 116, 117. 46 Almost a third of this amount is now committed as a result of a $270 contract with Itron, Inc., based in the state of Washington and two earlier contracts, one for $73 million with Corex to install meters and another for $63 million with Capgemini for information technology. Scott Simpson, “BC Hydro goes ahead with $270m smart meter contract: Digital metering of two million customers has energy minister’s support, Hydro says” Vancouver Sun, April 12 2011.
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The case for smart meters is that they will allow BC Hydro to eliminate energy theft, deal more expeditiously with system outages and enable the utility to make technical efficiencies in the management of its system. BC Hydro estimates that by 2033 the net present value of the saving resulting from the program will total $520 million. But its figures indicate that much of this projected saving will not be realized for many years into the future.47 BC Hydro estimates that the net present value of the potential savings from stopping marijuana grow-op theft alone will be approximately $730 million. This represents almost half of the projected benefits of smart meters. Without this assumption, the program will clearly lose money. The problem is that BC Hydro does not know precisely how large the theft issue is. Given the lack of detailed analysis, the figure is basically a ballpark estimate and one which seems extremely high. Moreover, BC Hydro does not know whether the new meters will even stop electricity theft, given the success of ‘hackers’ to circumvent the security arrangements of some of the most sophisticated computer systems. (And, the projected savings might vanish almost entirely if a US state such as California, actually legalized pot.) In other jurisdictions, the major rationale for introducing smart meters is to permit real time monitoring (time of use – TOU) of energy consumption by the utility and its ratepayers. TOU is normally introduced to permit variable pricing during a 24 hour period, with the highest rate corresponding to the peak demand period. But only about 7% of US customers currently have fully advanced, 2 way interactive TOU meters.48 Two way smart meters provide customers with information that may encourage them to reduce consumption during periods of expensive peak demand. BC Hydro has indicated it will provide this more advanced type of meter as an extra cost option to customers, but it is not part of the $930 million price tag.
that BC’s hydro based system does not have. Other jurisdictions are dependent on energy production from power plants, such as coal or nuclear, that cannot easily adjust their output to meet fluctuations in energy demand during a 24 hour period. Their problem is that output is relatively constant, while demand changes significantly, peaking at breakfast and during the dinner hour and falling off during the middle of the night. Hence, introducing time of use (TOU) pricing is a way to persuade customers to reduce consumption during periods of peak demand and increase it during periods of low demand. However, in BC it normally does not matter what time of day electricity is used. This is because BC Hydro’s is able to take advantage of its reservoirs with their large storage capacity to respond to the additional demand by running more water through the turbines in the big dams.49 BC’s capacity problem is a seasonal one, not a daily one. It comes normally in December, when the days are short, the nights are cold and people are using much more electricity. Meeting peak demand during the coldest days of winter is a serious issue. But it is not one that is resolved by TOU metering. The government also claims that Smart Meters will enable BC Hydro to deal more quickly with outages. However, BC Hydro already deals with outages relatively expeditiously without Smart Meters, so the potential benefits are relatively marginal, and far cheaper technical fixes to the network are possible to improve outage detection. Absent clear evidence of the size of the electricity theft problem and in light of the marginal potential gains from introducing TOU in BC, it is very difficult to see how the government can justify spending almost a billion dollars of ratepayers’ money on this initiative. In light of these factors, it is regrettable that the Review was not prepared to suggest that Smart Meters should, minimally, be delayed until there was clear evidence of their benefits in other jurisdictions.
Aside from the problematic savings from stopping theft, the major concern with smart meters is that they are a solution to a problem
47 BC Hydro, “Smart Metering & Infrastructure Monitoring Business Case” http://www.bchydro. com/energy_in_bc/projects/smart_metering_infrastructure_program.html 48 United States Energy Information Administration (EIA), “Today in Energy” March 15, 2011.
49 There can be exceptions based on transmission congestion in a few areas of the province and to non integrated areas. But the main population areas have access to the advantages of flexible reservoir storage.
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CONCLUSION The recent Review of BC Hydro was a major missed opportunity. The narrow focus the Government established for the Review resulted in a failure to address the fundamental reasons for BC Hydro’s current fiscal problems. These problems are rooted in the government’s electricity privatization policy and its energy intensive resource development strategies. The recommendations of the review wrongly place much of the responsibility for BC Hydro’s proposed rate hikes on the utility’s workers and on management’s inability to control costs. Its suggestion that somehow the management of BC Hydro had failed to let the government know the full dimensions of its financial and operational challenges is difficult to square with the overwhelming evidence that the government gave the corporation very specific policy direction, both through the two Energy Plans and through a number of specific pieces of legislation culminating in the Clean Energy Act. The government also appointed the utility’s Board of Directors and clearly was aware – and took credit for – virtually all the major initiatives the Crown Corporation pursued over the past decade. The Review’s proposals for reducing the size of BC Hydro’s rate increases over the next three years will only mean higher increases
further into the future. Ratcheting back some components of the utility’s capital investment plan and laying off large numbers of employees will likely weaken the corporation and limit its ability to oversee contracts with many of the projects from which it is purchasing power. Introducing public private partnership arrangements will only further expand the role of the private sector in its operations, introduce additional management complexity and make it more difficult for it to control procurement and other costs.
BC Hydro’s problems can only be fixed by fundamental changes in the government’s overall energy and economic development strategies. As long as the current policies remain in place, ratepayers can expect a succession of major rate hikes in the coming years. In addition, unlike the recent past, the government will no longer be able to benefit from the revenue generated by this corporation to fund other important public programs unless it is prepared to ratchet up rates even further. The one positive outcome of the Review is that it does question the value of the Government’s “self-sufficiency” policy and thus opens the door to a more rational examination of the extremely high costs of this initiative. If this leads to a basic rethinking of the policy by the government, the Review will have accomplished something, even if there is so much more that it ought to have done.
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Appendix 1: BC Hydro Rate Increase Requests (%) November 2011 2011
Projected Rate Increase
Projected Deferral Account Rate Rider
Projected Net Bill Impact
Projected Cumulative Net Bill Impact
Source: BCUC Order G-180-10 Dec. 2, 2010. J “F11RRA Settlement Agreement, Nov. 18, 2010. P. 9.
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Appendix 2: BC Hydro Ongoing and Proposed Major Projects Project
Southern ST’AT’IMC Community
Chekamus Spillway Gate Upgrade
Fort Nelson Generating Station
Smart Metering Program
Digital Smart Meters
Stave Falls Reliabilty Project
Columbia Valley Project
New Transmission Line
Vancouver City Central Project
Substation and Transmission
Dawson Creek/Chetwynd Project
New 230 kV Transmission Line
Mica Gas Insulated Switchgear
Replacement of Switchgear
Northwest Transmission Line
New Transmission Line
Interior/Lower Mainland Transmission
New 500 kV Transmission Line
Seymour Arm Project
New Capacitator Station
Ruksin Dam and Powerhouse
Seismic Upgrade & Powerhouse
Mica Units 5 and 6
Gordon Shrum Units 1 to 5
Totals Excluding Site C
New Dam and Generating Station
Totals Including Site C
Source: BC Hydro 2011 Annual Report, pp. 102 - 104
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Appendix 3: Summary of BC Hydro’s Outstanding Energy Purchase Agreements
No. Of Contracts
Total EPAs Signed
* COD = Commercial Operation Date Source: BC Hydro, F2012 to F2014 Revenue Requirements Application March 1, 2011 Chapter 4, Table 4 – 5 EPA Summary, p. 4-17.
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Appendix 4: IPP and Long Term Purchase Costs ($ million)
F2010 Actual F2011 Forecast F2012 Plan F2013 Plan F2014 Plan
Island Cogeneration Plant
2000 Green RFEOI
2001 Green Energy Call
2002 CBG Call
2002/03 GPG Call
F2006 Call (including Brilliant)
Alcan 2007 EPA
Bioenergy Call - Phase 1 RFP
2009 Clean Power Call
Standing Offer Program
Source: BC Hydro, F2012 to F2014 Revenue Requirements Application March 1, 2011. Chapter 4, Table 4 – 7. IPP and Long Term Purchase Costs. p 4 - 18.
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A C O MMENTARY ON THE JUNE 2011 R E V I E W OF B C HYDRO R E PORT
By C. Fussell, 2011 power.indd 30
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In summer 2011, the government released the BC Hydro Rate Review Report. The purpose of this report was to force BC Hydro to significantly reduce its immediate rate increase requirements. To achieve the rate reductions favoured by the review panel (8% in 2012, 3.9% in 2013 and 3.9% 2014 1) BC Hydro will have to reduce its current 2012 -2014 revenue requirement application by $60 million in 2012, $200 million in 2013 and $200 million in 2014.
There is little flexibility in making cuts to the cost of energy, which includes contracted payments to IPPs and water licence fees based on BC Hydro’s production at its heritage resources. A reduction in the water license fees collected by the government appears to be the only way to reduce the cost associated with this element of BC Hydro’s revenue requirements.
A number of the suggestions included in the review would result in reduced revenues to the province. The review was written before the rejection of the HST and the subsequent $1.6 billion increase in the province’s debt. This change, along with the fact that much of the monies generated through the Return on Equity charge will be required to maintain the 80:20 debt equity ratio, will leave little money for dividend payments to the province. As a result it’s unlikely in my view that the government will be prepared to accept any measures that reduces other revenue sources such as water license fees, within the three-year period of the 2012-2014 revenue requirement application. If the government is adamant that the rate targets included in the review be achieved, then cost reduction measures that don’t affect provincial revenues will have to be aggressively pursued. While the review makes a large number of high level recommendations it is not specific as to which elements of the current revenue requirements are expected to be cut. Table 1-1 2 of the 2012- 2012 Revenue Requirement Application sets out the following makeup of BC Hydro’s revenue requirement for 2012: Cost of Energy including water rentals ($325 Million) Operating Costs Taxes Amortization Finance Return on Equity (ROE) 1 See table, page 4 of Executive Summary of Review. 2 See page 1-8 of 2012-2014 Rev Req Application
$1324 million $1409 $187 $608 $506 $610
Water rental fees are indexed to reflect the BC Consumer Price Index. Prior to 2011, the fees were indexed to reflect the average price increase of BC Hydro’s rates. The change in indexing will reduce future government revenues over the next couple of years. The June 2011 review indicates that the fees paid by BC Hydro are high, almost twice those paid by Hydro Quebec or Manitoba Hydro3. In spite of this it is my view that the government will not accept a further reduction in future water rental fees in light of the recent significant increase in the provincial deficit. Therefore, the review turned to operating costs as the element of the revenue requirement over which BC Hydro’s current management has most control, is most flexible and if changed will be reflected immediately in rates. A change in operating costs to a much greater degree than the other elements of the revenue requirement is unhindered by BC Hydro’s past decisions. Any significant reduction to operating costs will include layoffs. Although a large number of individuals within BC Hydro work on both operating and capital investment activities, about 75% of BC Hydro’s workforce spends time on activities classified as operating. The rate review4 suggested that a workforce of 4800 is a reasonable level for BC Hydro. Achieving this would require a reduction of 800 from current staffing levels and reduce the workforce associated with operating activities by approximately 600. 31
3 Figure 3.2.1, page 95, Review of BC Hydro document. 4 Page 5 , Review of BC Hydro
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Figure 2.2.15 indicates that labour represents 43% of operating costs. A 600 or 15% reduction in staff is estimated to reduce operating costs by roughly $100 million dollars. However, it is worth noting the severance pay associated with the layoffs that resulted when BCTC and BCH were integrated completely offset the cost reduction due to reduced staff during the first year following the integration. The rate review offers the usual remedies for reducing costs, streamlining processes, consolidating functions, etc.6 It does not offer any useful insight into how BC Hydro is to operate, maintain and update its ageing infrastructure7 and provide reasonable service levels with a reduction in staff levels. I believe the 2012-2014 Revenue Requirement application included a reasonable effort in managing staffing levels. Table 5-8 of the application indicates a reduction of 411 FTEs (Full Time Equivalents) over the 2012 to 2014 period. Considering capital expenditures, the review indicated that BC Hydro has committed to reducing the capital additions by $800 million dollars8. While the review talks of reducing and deferring capital spending, the bulk of any capital reduction within the 2012-2014 time frame will be as a result of spending deferral. Any spending deferral in the current period will result in an increase in spending in future periods. If capital additions were reduced by $800 million by year 2013, the 2014 rate increase would be reduced by approximately 2% as a result of marginal reduction in finance, ROE and amortization charges. While it’s certainly feasible to delay capital additions such as the redevelopment of the Ruskin Power House from the current period to some future period, thereby reducing current rates, the shift in capital spending will not lead to any long term rate benefit. Recently9 the government changed how the ROE should be calculated, 5 See page `36 of Review. 6 See introduction to Operating Costs, section 2-2 page 35 of the Review 7 See pages 74-76 of Review. 8 Capital Cost Savings, page 82 of Review., 9 BC Hydro’s Current Capital Situation, page 97 of Review
stipulating that BC Hydro should be rate-based regulated with a deemed equity of 30%. BC Hydro’s actual equity is 20% and their debt 80%. In effect, the 10% of rate difference between actual and deemed equity attracts both an ROE charge and a debt financing charge. The review identified this issue and suggested a number of alternatives to address it. However the alternatives either increase rates or reduce dividends to the province. The review10 also addresses various policy issues. With respect to rate impact, the most important policy issue by far is the Clean Energy Act (CEA) requirement that BC Hydro plan on the basis of critical water to be self sufficient by 2016 and acquire a 3000 GWh surplus by 2020. The review suggested that if the current low market electric prices continue, rate increases could be mitigated by 20%11 by 2020 if the Clean Energy Act (CEA) planning requirements were changed. The difference in system energy capability between average inflows and critical inflows is approximately 5000 GWh. This means BC Hydro could reduce its planned energy requirements by 5000 GWh and would not have to acquire any new energy resources until at least 2016. Any supply shortfall that results if actual inflows are less than average would be made up through market purchases. One of the Clean Energy Association of BC’s arguments against allowing BC Hydro to adopt average inflow criteria is that market prices are unlikely to remain low, so long-term IPP contracts offer a good hedge against rising volatile market prices. Their support for the possibility of rising market prices is based on a BC Hydro electricity price forecast released in April 2011. A cursory examination of this forecast shows that the rise is due to the cost associated with the GHGs that result when electricity is produced from thermal generation resources. If GHG costs are not considered then the price forecast is flat, remaining under $50/MWh. The midelectricity forecast shows a rise to $60/MWh by 2020. By contrast, the average price for IPP energy in the recent Clean Call was $124/MWh: a significantly higher rate.
10 See pages 101 of Review. 11 See page 93 of Review
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The cost of GHGs is a function of government policy. While cap-andtrade and/or placing a tax on GHGs has been discussed for a number of years, nothing has been enacted in jurisdictions outside of BC. In view of the current economic conditions it is unlikely that any new legislation will be enacted in the short term that leads to an increase in electricity prices.
● Overall Conclusion – page 23
The overall conclusions presented on pages 19 and 20 are in my view fairly reasonable. However it’s difficult to see how these conclusions can lead to $200 million reductions in revenue requirement increases in order to achieve the reduced rate increases shown in Option 2 on page 21.
If the government wants to mitigate future rate increases then I would suggest the following:
The recommendations to include the Board and the Minister in more of the business details suggest that BC Hydro will see continued political interference in the foreseeable future, which is not consistent with the recommendation to streamline processes.
1. Proceed with Site C. 2. Fill any supply deficiency between now and the in-service date of Site C with market purchases. BC Hydro has imported up to 8400 GWh/year12 in the past. Given the abundance of supply as a result of the Renewable Portfolio Standards (RPS) in the California and other states there is little risk that BC Hydro could not get the energy. BC Hydro’s system is flexible enough to buy energy from conventional sources when it’s not needed to augment RPS supply sources. The price will be volatile, but given the large gap between the forecasted market price and IPP prices, $40-$60/MWh versus $124/MWh, it’s a reasonable bet to take. It’s very unlikely that the extreme prices, up to a $1000/ MWh, seen in 2001 will reoccur. The 2001 price spikes were the result of capacity shortages and as indicated above, the RPS criteria adopted in the US assures that there is likely to be ample capacity available to fill any BC Hydro energy shortfall. Once Site-C is completed much if not all of the market purchases can be replaced with clean Site-C energy.
COMMENTS ON SPECIFIC SECTIONS OF THE REVIEW Much of the material in the June review describes BC Hydro’s operations and management practices and offers little in the way of concrete suggestions as to how these might be changed to reduce costs. Here are some of my additional reflections: 12 See page 93 of Review.
● Recommendation re: BCTC Integration – page 24
The BCTC integration should have led to savings greater than the $25 million included in 2012 revenue requirement. A 5-10% reduction in T&D costs13 represents a 10-20 million reduction in revenue requirements.
● Recommendation re: Zero-Based Budgeting - page 34
Zero-based budgeting should be undertaken periodically and results should be part of BC Hydro’s revenue requirement filings.
● Section 2.23 – pages 34 - 45
All of the recommendations included in this section are reasonable, especially the final recommendation concerning the effectiveness of new IT processes. In the future I would suggest that any request put before the Commission for a new IT process must include a description of a succeeding study that will evaluate the effectiveness of the requested IT investment.
● Further Opportunities for Cost Savings - Section 2.24 and 2.25 – pages 46 – 57
If management adopts the very aggressive approach suggested by the review, the outcome will be a very demoralized BC Hydro staff. The politically-motivated review has already demoralized staff. BC Hydro has employees throughout the province. If changes are aggressively implemented the government could feel the consequences.
13 See page 24 of Review
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● Procurement - Section 2.3, pages 57 – 63
● Class Cost Recovery - pages 81 - 91
● Procurement Options Recommendations - page 68
● Self Sufficiency – pages 92 - 93
These recommendations appear very reasonable. Management support in the implementation of technology projects needs to be improved. BC Hydro in past revenue requirement applications has paid lip service to this issue; however, there has been little evidence indicating that effective change management has occurred.
The recommendations appear reasonable. It is difficult to imagine any BC Hydro projects being procured through a PPP arrangement given that PPPs are long term and include operations as well as construction.
BC Hydro backed away from a design-build approach and used a design-bid-build approach for the SMI project.14 BC Hydro felt the bidders wanted too much for the assumed risk they would undertake in a design bid build undertaking. As indicated in this section, understanding risk and its associated costs is critical in determining the appropriate approach. Seemingly, a competitive process does not assure a reasonable outcome.
Government should not establish ranking or priority weighting amongst competing rate design objectives. The proposal would reduce the complex balancing of competing factors which has evolved in the hands of utility regulators across North America and beyond, into a formulaic approach which is incapable of achieving the purposes of rate design. This section is counterproductive, and if this recommendation is put in place I predict that rate design changes will come to a complete standstill. The government could and has through policy direction indicated a general direction that should be emphasized when re-designing rates. In the past, energy policy statements have emphasized conservation, leading to concerted effort on BC Hydro’s part to implement conservation rates.
14 See page 2 SMI Business Case filed with BCUC Dec 23 2010.
This is an area where government change would have a big impact on future rates, starting 4-5 years out, without affecting current revenue from BC Hydro. If this change is linked to Site C, then the government can maintain the 93% clean target. The potential future rate impact due to the amortization of BC Hydro’s large deferral accounts adds further pressure for the government to do something about the longer term rate impacts of self sufficiency.15
● Capital Assets – page 98
● Recommendation re: Rate Structure - pages 85 - 86
It is difficult to understand why this issue was addressed except perhaps to try to ensure that residential customers see the full benefit of any cost reductions. On the other hand, it could signal a renewed effort to rebalance rates by shifting cost from commercial customers onto the residential class.
Additional borrowing to fund deferral accounts covering operating costs or new capital additions not yet in service results in less money for dividend payments to the province. Every billion dollar increase in borrowing will reduce the dividend to the province by around $300 million dollars in the year the borrowing occurs, a onetime cost of $250 million to maintain the 80:20 debt equity ratio and $50 million (5%) to cover ongoing interest costs.
● Adoption of IFRS and ASC 980 – page 110
From a long-term rate level perspective this change should make little difference. Income may be more volatile as a result, but longrun revenues collected from ratepayers will be the same.
● DSM – page 116
A revaluation of DSM with a focus on cost reduction is overdue. Once the Clean Energy Act came in, the sense was that Power Smart was untouchable when it came to curtailing costs. 34
15 See discussion on regulatory assets pages 110-114 of Review.
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● Smart Meter Initiative –pages 115 -116
The evaluation of the SMI included in the Review is shoddy. The Review puts forward BCH’s business case in spite of the fact that government insists time-of-use rates will not be implemented. In addition, energy savings associated with the in-home display will be much reduced if, as suggested, the in-home display units are not subsidized.
FINAL OBSERVATIONS This review will have a significant impact on BC Hydro and intervenors’ positions at the upcoming revised revenue requirement hearing. In past, BC Hydro has always adopted the position that the revenue requirement request is as low as it can be, that there isn’t any fat to be trimmed, they’ve turned over every stone in search of savings, etc. It’s now very clear that there are more changes that can be made. Hopefully this will encourage the BC Utilities Commission to be more aggressive in reducing utility-requested increases in the future, but it may be difficult to get the BCUC to move off the perceived political direction in arriving at its decision regardless of the evidence presented during the hearing. Intervenors’ role will change. Rather than just concentrating on identifying potential revenue requirement reductions they will have to look carefully at BC Hydro’s proposed cost reductions to ensure that they make sense from a long-term business perspective, rather than simply being a short term fix to satisfy government.
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The Canadian Office and Professional Employees Union Local 378 2nd Floor, 4595 Canada Way, Burnaby, BC V5G 1J9 TEL 604-299-0378 TOLL FREE IN BC 1-800-665-6838 FAX 604-299-8211 www.cope378.ca
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Published on Jun 11, 2013