British Columbia Industrial Electricity Policy Review. Written Submissions of the Association of Major Power Customers of BC

Transcription

1 British Columbia Industrial Electricity Policy Review Written Submissions of the Association of Major Power Customers of BC March 27, 2013

2 Table of Contents I. INTRODUCTION AND BACKGROUND... 1 II. SUMMARY OF CONCLUSIONS... 3 III. DISCUSSION... 4 A. Renewed Focus on Lowest Cost Rates Discussion Paper: The Evolution of British Columbia s Industrial Electricity Policy Issue Paper: Economic Development Issue Paper: Environmental Policy Issue Paper: Retail Access... 7 B. Contribution Policy Issue Paper: Generation Contribution Policy Issue Paper: Transmission Contribution Policy... 9 C. Return to Traditional Utility Regulation of BC Hydro Issue Paper: Regulatory Approach for BC Hydro Issue Paper: Postage Stamp Rates Issue Paper: End-Use Rates Issue Paper: BCUC Stepped Rate Recommendations IV. CONCLUSIONS Appendix A Electricity Rates in BC Appendix B Rate Design Terminology Appendix C BC Hydro 2012 FACOS Study

3 I. INTRODUCTION AND BACKGROUND On January 24, 2013, the Ministry of Energy, Mines and Natural Gas (MEM) announced that this Task Force would undertake a review of industrial electricity policy. The Association of Major Power Customers of BC (AMPC) appreciates the opportunity to participate in this important review which is, in its view, vital to securing the economic future of BC. Formerly known as the Joint Industry Electricity Steering Committee (JIESC), 1 AMPC is an incorporated not-for-profit society and industry association that represents major industrial load customers in matters of electricity regulation. AMPC and its predecessors have participated in every major BC Hydro revenue requirement or rate design regulatory proceeding since BC Hydro came under active regulation in the early 1980s. AMPC members are transmission level customers of BC Hydro in the pulp and paper, forestry, mining, electrochemical, petrochemical, and petroleum sectors, and collectively represent a significant majority of BC Hydro s large industrial load. In 2011, for example, AMPC member purchases comprised approximately 80% of BC Hydro s industrial load of almost $600 million. A number of AMPC members operations also include generation facilities. This review is to consider existing industrial electricity policy and the current regulatory framework, consult with industrial stakeholders, and report to government. The task force s Terms of Reference establish its purpose and mandate as follows: 3. Purpose The purpose of the Review is to examine the current industrial electricity policy and regulatory framework, identify policy issues affecting transmission service customers, consult with affected stakeholders, conduct an integrated analysis, and make recommendations to the Minister on potential changes to the current policy and regulatory framework. 4. Task Force Mandate The task force is directed to make recommendations on the following: A. the extent to which the transmission voltage rates may be used to contribute to provincial electricity conservation objectives, and the changes, if any, that would be appropriate to those rates or the current regulatory framework to achieve those objectives; B. the extent to which the transmission voltage rates may be used to contribute to provincial economic development objectives, and the changes, if any, that would be appropriate to those rates or the current statutory and/or regulatory framework to achieve those objectives; 1 JIESC comprised the Council of Forest Industries, the Mining Association of BC, and a number of other industrial operations.

4 2 C. the extent to which the transmission voltage rates may be used to contribute to provincial environmental policy objectives, and the changes, if any, that would be appropriate to those rates or the current regulatory framework to achieve those objectives; D. the implications of pursuing each objective in relation to the other two; and E. Principles to guide the Province concerning the use of its directive powers related to the Commission and/or BC Hydro in order to pursue provincial policy objectives. The task force is to consider the following while developing its recommendations: 1. the appropriate allocation of BC Hydro s incremental and embedded costs, including generation and transmission costs, when new customers request service or existing customers request increased service; 2. whether and postage stamp rates remain appropriate for customers taking service at transmission voltage rates; 3. whether end-use rates are appropriate for customers taking service at transmission voltage rates; 4. whether retail access rates would be appropriate for customers taking service at transmission voltage rates; 5. whether it would be appropriate to act on any of the recommendations contained in Commission Report on the TSR; 6. how current transmission voltage rates compare with rates for similar types of service in other jurisdictions in Canada and the Western Electricity Coordination Council area; and 7. any other considerations related to current or future operation of transmission voltage rates the task force determines necessary in making its recommendations. Clearly, this is a very broad mandate with the potential to significantly impact industrial rates in BC in the future. AMPC s written submissions follow a procedural meeting and subsequently, a substantive meeting with the Task Force, and benefit from the Discussion Paper and Issue Papers that the Task Force released as starting point discussion pieces between those two meetings.

5 3 Those papers addressed the following topics: Discussion Paper The Evolution of British Columbia s Industrial Electricity Policy Issue Papers Regulatory Approach for BC Hydro Retail Access Transmission Contribution Policy Environmental Policy BCUC Stepped Rate Report Recommendations Economic Development End Use Rates Postage Stamp Rates II. SUMMARY OF CONCLUSIONS Having considered the task force s Issue Papers and the initial discussion with task force members, AMPC proposes three broad recommendations for the task force to make to government: a) Direct BC Hydro to renew its focus on achieving the lowest cost electricity rates that guarantee reliable service, as a single and overarching economic development objective. b) Direct BC Hydro to design and implement a transparent, universal and principled transmission contribution policy as soon as possible. Ideally this would be done before any more customers are contracted for service at transmission level. c) Recommend a full return to traditional utility regulation of BC Hydro by the British Columbia Utilities Commission (BCUC) free from government/shareholder interference. More specific choices that should be made as part of doing so are discussed below. AMPC has structured its discussion to follow and respond to the task force s Issue Papers.

6 4 III. DISCUSSION A. Renewed Focus on Lowest Cost Rates 1. Discussion Paper: The Evolution of British Columbia s Industrial Electricity Policy The starting point for the task force s review of industrial rates should be the questions are BC industrial rates internationally competitive? and what is the current trend of BC s industrial electricity rates? The frank answers are that as a result of steady and sustained increases, BC s electricity rates are no longer competitive in some key markets and face severe pressure to increase further, as is confirmed by BC Hydro s most recent service plan. During BC Hydro s last Revenue Requirement application, AMPC submitted evidence showing that, within Canada, BC Hydro industrial rates were higher than those of Manitoba Hydro, Newfoundland & Labrador Hydro, and Hydro Quebec noting that the remainder of Canadian jurisdictions do not benefit from the large-scale hydraulic resources that these four provinces do. 2 BC businesses, however, are natural resource and export oriented, and hence, compete on the world stage. BC must compete globally not only to retain existing economic activity, but also to attract new investment. The closest comparison of electricity prices is across the BC-US border at the Mid-C trading hub. Per MW.h spot prices during 2012 ranged between $2.65 and $43.04, generally fluctuating between $20 and $30. These prices are generally lower than to BC Hydro s 2012 Tier 1 price of $32.61/MWh and Tier 2 price of $73.60/MWh, even before the base demand charge, 5% rate rider, and 7% PST are added. BC Hydro is currently paying many IPPs over $120/MWh, well in excess of the market price for imported electricity, for firm energy it does not need. The Review of BC Hydro report dated June 2011 by a panel of BC Deputy Ministers is a good starting point when considering the future competitiveness of BC s industrial electricity rates. The review was the product of an extensive review of BC Hydro s operations by senior government officials, with the benefit of a team of staff having unprecedented access. A multidisciplinary team of 20 professionals worked at BC Hydro for almost seven weeks, receiving the utmost cooperation and support". The report clearly showed that BC Hydro faces material challenges in trying to moderate rate increases in the foreseeable future. The report s conclusions were that, among other things, BC Hydro suffered from gold standard and risk adverse mentalities, resulting in work silos, inefficiencies, and duplication that magnified costs and created a culture that sought to justify cost increases rather than work from a zero-based budgeting approach. 3 This indicates a clear loss of focus on delivering low-cost electricity that was BC Hydro s genesis, and suggests that sweeping changes are necessary to restore an appropriate culture. Notwithstanding this, it does not appear that much has been done to attack the root causes of BC Hydro s escalating rates. This Policy Review Task Force should assess, as part of its mandate, the extent to which the Deputy Minister Review Panel s recommendations have been, or can be, further implemented. 2 Ex. C18-4, p. 4, Project No / Order G Review of BC Hydro, June 2011, Government of British Columbia, pp. 2-3 and

7 5 The 2011 report s conclusions come despite the fact that, historically, BC Hydro offered BC industry world-leading electricity rates and, in so doing, a material competitive advantage. These low rates were the product of the Columbia River Treaty (CRT) and Bennett Dam investments in the 1960s and early 1970s. These decisions proved to be far-sighted the initial flood control objectives of the CRT have been robustly complemented by the benefits of abundant power supply. Other policy trends following the installation of heritage generation have contributed to the rise in BC s electricity costs. A notable example is the decision by BC Hydro s shareholder to increase its dividends through the 1990s by freezing rates in an era of falling interest rates that would have otherwise justified a decrease in BC Hydro s rate levels or built reserves. This meant that monies paid by ratepayers that were required to upgrade and maintain the BC Hydro system were directed to the Province, rather than utilized within BC Hydro where they were needed. Other policy decisions that have increased rates include the Clean Energy Act (CEA) requirements of insurance, selfsufficiency, and a 93% clean standard led to BC Hydro purchasing more high-cost intermittent energy than needed and put further upward pressure on rates, as did the CEA 66% conservation objective. The emergence of de-centralized generation via co-generation in the late 1980s required more widespread access to existing utility-owned transmission in order to balance load and to sell or trade surplus energy with other customers. 4 In many jurisdictions across the globe, this new dynamic drove changes to electricity utility regulation. While vertically integrated utilities are still common, many must now allow wheel-through access to transmission and purchase electricity from independent power producers (IPPs). Tariff Supplement #6 (TS#6) sets out the terms and conditions on which new load gains access to the BC Hydro system. Unfortunately, it has not been changed since TS#6 creates a sharp increased cost obligation that of incremental generation when a customer s demand exceeds 150 MVA. This feature was designed to discourage very large new industrial loads from seeking utility supplied electricity. Policies implemented under the CEA further exacerbate this requirement by driving up the marginal cost of power in British Columbia. BC Hydro has also been directed by government to undertake a significant amount of programming that is surplus to the functioning of a traditional utility. Much of its Demand Side Management (DSM) initiatives are not capable of independently demonstrating a positive return on investment (where they do, AMPC supports them). Social outcomes and ambitious environmental objectives (well beyond those demanded of other industry participants) have been stressed to the detriment of economic development and cost effectiveness, all of which has resulted in relentless upward pressure on rate levels. To a significant extent, the immediate impacts on rates of these actions were disguised and dividends maintained by the growing use of deferral accounts, which eventually ballooned to exceed BC Hydro s annual revenue levels (an issue that did not escape the attention of the Auditor General). While there is a place for deferral accounts to achieve rate stability and protect ratepayer generations from the vicissitudes of weather, water 4 Co-generation is also widely viewed as environmentally friendly.

8 6 levels and shared river systems, the deferral of current period costs inappropriately requires future ratepayers to pay for the costs incurred by today s rate payers and removes incentives for BC Hydro to make more cost effective decisions. Reversing these trends that put upward pressure on rates is now more important than ever. Since 2010 at least, BC has been presented with very significant opportunities for economic development of its natural resources. In particular, for mineral extraction in the NW, shale gas development and pipelines in the NE, and large LNG opportunities on the North Coast. These changes could be as significant for the BC economy as the CRT was in the 1960s or the oilsands were for Alberta in the 1970s. All of these developments require the timely expansion of stable electricity infrastructure at predictable, stable and competitive prices without placing undue rate pressure on existing customers. As discussed further below, AMPC believes this objective can be achieved via transparent and traditional utility regulation and an appropriate transmission contribution policy. 2. Issue Paper: Economic Development Two issues arise from this paper. First, the paper comments on the importance of electricity to industrial customers in certain industries, and notes that Vancouver ranks relatively well relative to other North American cities. Surprisingly it does not undertake a survey of electricity rates nationally or internationally for large industrial customers in areas relevant to BC s economy to substantiate this claim. Electricity costs are important to virtually all industrials and are the intended focus of this review. As Appendix A demonstrates, competitors to British Columbia industrial firms have substantially improved their relative competitive position with respect to electricity rates in recent years and are expected to continue to do so in the future. In addition to different electricity rates in competing regions, there are also differences in electricity incentive programs. For example, Ontario industrials have the North Industrial Electricity Rate Program which provides a rebate of two cents per kwh 5 and Oregon industrials have market access 6. This cannot continue without badly harming the economy of British Columbia. Second, the paper presents a choice between creating jobs (facilitating new load) and preserving jobs (avoiding rate pressure). AMPC submits that this is a false choice, as the tension identified is typically managed using a combination of long-range planning and an appropriate contribution policy embedded in a tariff, without the need for active government intervention. In today's competitive market, it is not appropriate for one customer to cross-subsidize another. Rates should not prefer old or new customers or any particular industry or end-use. 5 The Northern Industrial Electricity Rate (NIER) Program assists Northern Ontario s largest industrial electricity consumers and key economic contributors to reduce energy costs, sustain jobs and maintain global competitiveness. When the proposed program begins on or around April 1, 2013, current participants would continue to receive a rebate of two cents per kilowatt hour with individual rebates capped at consumption levels, or $20 million per year per company whichever is lower. 6 Since 2002, Oregon has allowed customers access to market-based options either from the utility or from an Electricity Service Supplier.

9 7 The economic policy that should drive BC s industrial electricity policy is achieving BC Hydro s core purpose which is to provide safe, reliable electric service at the lowest reasonable cost and with due regard to competitive and environmental considerations. AMPC is confident that doing so will help BC industry be internationally competitive. BC Hydro should be organized, regulated and given incentives to focus on this goal. As a first step, AMPC requests a clear recommendation from the task force to stop the use of deferral accounts that cover what are really current period costs, and the establishment of a transparent plan to manage the reduction of the current high levels of deferral accounts to more sustainable ones, possibly by way of financial write-offs. Likewise, other costs of building, maintaining and operating the system (including water rentals) must be brought under control and reduced by the discipline that only competitive markets or effective and transparent independent regulation can bring to bear on the utility shareholder. 3. Issue Paper: Environmental Policy This Issue Paper notes that the shareholder has legislated environment-oriented provincial energy objectives that BC Hydro must comply with, unlike other electricity generators in BC or elsewhere, raising the question of what the corresponding cost to ratepayers will be. AMPC submits that this Task Force should recognize clearly that government policy under the Clean Energy Act has increased costs to BC Hydro customers. Examples of this include the limits on the use of natural gas and the requirements to purchase excessive amounts of firm energy from IPPs based on an ill-advised definition of selfsufficiency. Natural gas generation provides strong cost and reliability benefits to the system and must be considered as a viable and attractive generation option now and in the future. The Burrard gas generation facilities in particular are badly undervalued in system planning. AMPC believes that environmental and social policy should not be company specific. BC Hydro should be managed like a utility, not a social service or agent of social change. The shareholder is free to develop and implement stand-alone and broadly applicable environmental programs and policies targeted at the entire economy. Attempting to achieve equivalent or partial outcomes by adding such responsibilities to BC Hydro and thereby transferring costs to ratepayers from taxpayers is a practice that must stop if rates are to be competitive. The tangible harms are the erosion of low cost rates for all ratepayers, the removal of a competitive advantage for BC industry, and a public misunderstanding of costs and benefits of environmental policies. 4. Issue Paper: Retail Access Retail access consists of establishing mechanisms that would allow industrial customers to import and wheel power over BC Hydro infrastructure on a regular basis. The customer would, in effect, substitute market supply for some or all its current BC Hydro supply. The customer would assume the risks and gain any corresponding rewards the market offers, but potentially leave BC Hydro and the remaining customer base with the costs of generation developed for it.

10 8 The Issue Paper identifies the primary issue clearly: enabling BC Hydro's industrial customers to access market priced energy when prices are low may improve their competitiveness, but also exposes remaining BC Hydro ratepayers to the costs of stranded assets. AMPC submits that retail access is an important option for industrial customers because it offers the customer an opportunity to cut costs and it sets a clear benchmark for judging the efficiency of BC Hydro and its operations. In some cases, the availability of a retail access choice might mean the difference between a customer continuing operations in the long run or shutting down. Retail access is not just about capturing lower pricing and being able to access market at times when market prices are lower than the cost of local utility service. Retail access also provides customers choice in providing options that the local utility service might not be able to offer. Some of these choices include: Pricing options fixed, indexed, etc. Product quality firm vs. interruptible service Product type green/renewable electricity supply options Contract certainty negotiated contract terms & conditions including future price levels Diversification of electricity suppliers Ability to gain market experience AMPC accordingly welcomes a dialogue to discuss implementation of retail access and the development of tariffs. A pilot program, like the one that was recently suspended should be reinstituted as soon as possible. AMPC members are frustrated that this pilot program was suspended in reaction to customer moves to give it a try. AMPC recognizes that in implementing retail access there will have to be rules governing the terms on which customers may depart from, or return to, embedded cost service. These issues can certainly be managed. For example, AMPC understands Oregon has done exactly that. 7 B. Contribution Policy 5. Issue Paper: Generation Contribution Policy In AMPC s view, generation and transmission contribution policies should not be considered as distinct items. With the important exception of dedicated local generators that may displace distribution or area transmission reinforcements, the cost of expanded system generation is not normally included by utilities as part of the system expansion costs to be recovered in a workable contribution policy with good reason. 7 Oregon implemented an electric industry restructuring law that took effect March 1, 2002 that allows customers to choose between regulated cost-based and market-based options, either from the utility or from an Electricity Service Supplier.

11 9 Generation is the most communal part of system that cannot be causally mapped to any specific customer, and is difficult to establish on a principled basis. An existing customer who fails to conserve contributes to the need for generation in a similar manner to the new customer seeking to join the system for the first time. Furthermore, new generation often comes in large distinct quantities and accordingly, the first customer may have an infinite marginal cost and the second, a zero marginal cost. Attributing generation cost is challenging in practice, not just theory. Generators are planned in aggregate (along with integrating transmission) to meet aggregate load and growth in load not to serve a specific load, as there are large economies of scale and scope in aggregate planning. 8 As a hypothetical example, allocating the cost of Site C to one LNG liquefaction plant but not another would be practically and politically infeasible. 6. Issue Paper: Transmission Contribution Policy This Issue Paper notes potential inequities with the arbitrary 150 MVA cut-off embedded in TS#6. AMPC agrees the policy cut-off is arbitrary and discourages new load and associated economic development. This is one of three significant problems with TS#6. It also arbitrarily differentiates between new customers that require radial transmission and new customers that require major network investments. The third problem is that TS#6 takes an all or nothing approach to the roll-in of costs and misses the opportunity to find an intermediate roll-in percentage that can better balance encouraging growth and stabilizing rates. The unfortunate result of these flaws is that TS#6 treats the three following situations with identical cost causation as if they are fundamentally different, resulting in wildly different contributions being required from customers who may place similar costs on the system: 1. New transmission customer requiring major network investments: Generation costs 100% roll-in, Transmission costs 100% roll-in. Customer contribution: Zero. 2. New transmission customer requiring a radial extension: Generation costs 100% roll-in, Transmission costs 0% roll-in. Customer contribution: Very Significant. 3. New transmission customer larger than 150MVA requiring a radial or network investment: Generation costs 0% roll-in, Transmission costs 0% roll-in. Customer contribution: Volatile and likely Insurmountable. These arbitrary and massive differences contrast with other utility practices (such as those in Alberta) that recognize such roll-in decisions need not be all or nothing and have adopted a more balanced approach to encourage economic development of remote areas, without presenting excessive rate increases to existing customers. An effective system reinforcement or contribution policy balances the desirability of adding new customers and associated economic growth with the possibility of putting too much pressure on the rates for all customers. This balance is achieved through a careful 8 The aggregate planning of generation notably forms the economic basis for DSM funding. Each existing load that does not conserve a MW is considered as responsible for the cost of a new MW of generation as the growing load that adds a MW.

12 10 consideration of transmission cost causation and selection of roll-in percentages somewhere between 0% and 100%. Determining the appropriate percentage for rolling is a complex process and should be the subject of a BC Hydro Application and a BC Utilities Commission process, not a Government direction. BC requires a well-balanced, transparent and stable contribution policy that is consistently applied to all new developments to maintain stable and predictable postage stamp rates, in turn encouraging orderly and efficient economic development. Generation costs are not relevant to a contribution policy unless that generation is local and can economically substitute for more expensive transmission additions. AMPC urges the task force to, instead of restricting the existing contribution policy, recommend the development and implementation of a new and revised contribution policy as a simple and powerful tool to send transparent and fair price signals, mitigate rate pressure, and efficiently accommodate incremental development. A step-by-step approach to achieving a sound long term contribution policy is as follows: 1. Identify each new load (or group of loads) and select the least (incremental) cost option from a number of alternatives (including the possibility of local generation). Incremental costs include all significant area transmission and distribution costs, regardless of their network or radial nature. Incremental transmission costs are allocated between existing and new loads if costs are jointly incurred to remedy service levels. 2. By inspection of multiple forecast developments, determine a generic Roll-in- Ratio to divide the above costs between new customer contributions and a utility investment or amount to be recovered from all customers through postage stamp rates. AMPC believes that a suitable Roll-in Ratio (RIR) can be found that allows desirable new loads to be accommodated at acceptable levels of contribution without placing significant upward pressure on rates. Illustrative examples are provided further below. 3. By examination of a number of expected developments, convert the desired RIR into a simple to administer published tariff expressed as a multiple of annual rate revenue or contract demand of the new customer(s). If the target roll-in is 75% of incremental costs 9, and 25% of costs are to become an upfront contribution, this would be expressed as a "times revenue" utility "investment" in the actual tariff. The target RIR does not appear in the tariff itself it is a "background" calculation to arrive at an appropriate multiplier. For instance, a target 75% roll-in percentage might translate (based on projections of forecast scenarios) as a utility investment level of 2.5 times the annual revenue from the new service(s). It could also be expressed as utility investment of $ dollars per KVA of customer new contract demand. Note that the precise numbers used are for illustrative purposes and not the result of 9 75% is assumed to be a pro-development RIR. 0% ( as occurs in TS#6 for radial extensions) might be considered an active discouragement of development, and 50%a more neutral figure. The point being that the RIR can be tuned to the development levels and rate increase levels that can be sustained)

13 11 an actual forecast calculation, which is complex and can only be performed by the utility. 4. Apply the tariff contribution policy (as an annual revenue multiplier or $ per KVA) consistently and without discrimination to all new and proposed developments regardless of the actual cost ratios realized in each case. Avoid any sudden and arbitrary discontinuity such as the radial/network distinction or 150 MVA cut-off featured in TS#6. 5. Monitor contribution levels and further expansion plans to ensure that the postage stamp rates will remain stable and provide periodic reports to the regulator as part of each tariff review. C. Return to Traditional Utility Regulation of BC Hydro The task force issued four Issue Papers that contemplate moderate to severe changes to how BC Hydro s rates are set and what BC Hydro s relationship to the BCUC ought to be. One paper explicitly addresses the latter relationship, and the other three papers discuss ending the current industrial stepped rate structure, implementing end use rates, or moving away from something as fundamental as postage stamp rates. AMPC broadly supports a return to standard or traditional independent rate regulation by the BCUC. Shareholder directions and legislative prescriptions for BC Hydro alone, such as those contained in the Clean Energy Act, should be minimal. The competing policy drivers should either be addressed before the Commission, where they can be tested and placed in context relative to other aspects of the regulatory environment, or the subject of government action without using BC Hydro as a policy vehicle. The following discussion elaborates in relation to each Issue Paper. 7. Issue Paper: Regulatory Approach for BC Hydro This Issue Paper identified two major issues dealing with how BC Hydro ought to be regulated: what an effective regime should look like, and the extent to which government policy objectives ought to be advanced by rates. The regulation of BC Hydro has been replaced over time by shareholder legislation and directives that have removed virtually all major expenditure decisions from the review of an independent regulator. Revenue requirements are being set by Cabinet. There has been no thorough review of long-term plans or rate designs for many years. BC Hydro should be returned to effective and meaningful independent regulation for integrated resource planning, major facility needs, revenue requirements and rate design and administration. Reliable and cost-effective service from BC Hydro is best achieved by leaving the running of BC Hydro to its management and the regulation of BC Hydro to the BCUC. Businesses become more efficient, cost-effective and provide good customer service in response to the competitive pressures of the marketplace. Franchised monopolies such as BC Hydro are protected from such competition. Absent effective regulation, they have little or no incentive to become efficient, cost-effective or to provide good customer service. The role of a regulator is to emulate the pressures of competition and to discipline the shareholder with incentives for effective behavior.

14 12 For an electric utility that is not subject to retail or wholesale competition, it is therefore imperative that an independent regulator transparently determines the need for all new facility additions, approves a prudent level of allowed revenues, and determines all of the tariffs that are in effect. This is what market forces would do in a competitive scenario. While it may be tempting for government to attempt to achieve many social and other objectives through involvement in BC Hydro's day-to-day activities, AMPC recommends government treating BC Hydro as any other corporation in the province, subject to the same environmental objectives and social standards. Government objectives can be achieved separately and transparently. 8. Issue Paper: Postage Stamp Rates AMPC does not propose any changes to postage stamp rates, and submits that they are practically necessary and an underlying principle to other tariff structures in BC, such as transmission contribution policy. AMPC expects that there would be very strong and widespread opposition to any departure from postage stamp rates in BC. While the Issue Paper floats the concept of locational marginal costing to set rates, AMPC observes that proposals to use Long Run Marginal Pricing (LRMP) as the basis of pricing electricity transmission in Alberta were abandoned many years ago due to their complexity and fierce customer resistance. Applying the concept in BC appears equally complex, and AMPC opposes doing so. Setting rates based on market prices rather than embedded costs is also inconsistent with rate design principles of treating different vintages of customers equally. As discussed above, as postage stamp rates recover average costs of service, they must be protected against the roll-in of much higher marginal costs during periods of high growth. Although most customers support the extension of the system to serve new customers even if it means modestly higher rates, there is a limit to the costs of serving new customers that can reasonably be sustained. This is the basis of a contribution policy whereby customers with unusually high costs for initial service pay an upfront contribution to offset these higher costs and preserve the stability of the postage stamp rate. It is critical to note that stable postage stamp rates cannot be maintained without a customer contribution policy that carefully balances the interests of new and existing customers. 9. Issue Paper: End-Use Rates The Issue Paper proposes End-Use Rates as a legitimate and uncontroversial option to achieve provincial policy objectives, mirroring existing rate structures. However, AMPC believes these premises to be incorrect. AMPC believes an End-Use Rate is a euphemism or term of art for a rate that is deliberately designed to provide service below cost in order to achieve a specific social objective. The classic example is rates for places of worship or non-profit organizations. These sorts of end-use rates have existed since the beginning of the utility business before it became regulated, but have largely been removed since the 1980s in recognition of the inappropriate subsidies and encouragement for inefficiencies involved. To help understand AMPC s concern in more detail, a discussion of concepts relevant to

15 13 rate design associated with End-Use Rates and how they relate to rate design principles, definitions and existing tariff structures follows in Appendix B. Other examples of rates commonly described as End Use Rates include lighting, irrigation, interruptible, electrolytic, opportunity or market rates that may appear to be end-use from the common understanding of the term. These special rates are, however, usually cost based rates, and do not exemplify what a rate designer would consider true End-Use rates. For example, the cost of lighting rates is established based on a calculation that considers the size of lamp and lumens provided. In simple English, this is end-use. But the use of that term in a rate design context implies that the rate deliberately underrecovers the cost of the service to achieve a policy objective, which is not the case in BC or, generally, elsewhere. A lighting rate calculated this way is often done to chiefly to avoid the cost of metering, as the consumption level of a lamp can be calculated from its size and known burn hours determined by photocell or time switch. The utility may even provide the lamp and structure, as it can do this more cost effectively than a municipality or homeowner. Streetlight rates usually recover their full cost of service (and often more). Similar considerations apply to irrigation rates based on seasonal surplus supply. Failure to regularly review such rate designs may well allow cross-subsidies by neglect. AMPC submits that it would be retrograde and entirely inappropriate to consider the reintroduction of End-Use Rates to BC. They are antithetical to both signaling efficient usage and fairness in the allocation of costs, and clearly violate or threaten most of Bonbright s eight rate design principles: 10 Violated Principle 2: Fair apportionment of costs among customers (appropriate cost recovery should be reflected in rates). Principle 3: Price signals that encourage efficient use and discourage inefficient use (consideration of social issues including environmental and energy policy). Principle 4: Customer understanding and acceptance. Principle 8: Avoidance of undue discrimination (interclass equity must be enhanced and maintained). Threatened Principle 5: Practical and cost effective to implement (sustainable and meet long-term objectives). Principle 6: Rate stability (customer rate impact should be managed). End use rates are accordingly a departure from AMPC s core goal of achieving the lowest-cost rates possible for all customers while ensuring reliable service. 10 See James C. Bonbright, Principles of Public Utility Rates, Columbia University Press, 1961, cited and discussed in BCUC Decision on the British Columbia Hydro and Power Authority Residential Inclining Block Re-Pricing Application (attached as Appendix A to Order G dated March 14, 2011); BCUC Decision on FortisBC Energy Utilities Common Rates Amalgamation and Rate Design Application, February 25, 2013.

16 Issue Paper: BCUC Stepped Rate Recommendations The Transmission Service Rate (TSR) with stepped or inclined block energy charges was the first conservation rate to be designed by BC Hydro based on 2002 policies, and has served as the model for more recent inclined block conservation rates for the Residential and General Service classes. For the reasons below, AMPC does not support near-term changes to the model. Inclined block rates are considered to provide an efficient price signal reflecting the marginal cost of supply at the customer s marginal point of consumption (the last or next KWh) while maintaining a revenue to cost ratio close to the 100% design target. If the entire energy charge were to be made equal to the marginal cost of supply, then the rate would significantly over-recover costs to the unfair benefit of the shareholder or other customer classes. Inclined block or step rates are not common, as they have significant practical challenges in implementation. The level of the higher last block is controversial, and it is unclear if it is more efficient to reflect short-run marginal costs, long-run marginal costs or something in between. The higher the last block becomes, the lower the first block, and the utility s revenue stream becomes more volatile and risky as a result of forecast error in sales. Success in encouraging more conservation results in revenue losses for the utility and this could create pressure to increase rates, as the utility s own supply arrangements are less flexible. The Issue Paper reviews several potential areas of change, including: (a) Basing rates on cost effective performance measurements such as energy use per unit of output ( energy intensity ). (b) Difficulties encouraging conservation with a step rate once most customers are at, or near, the 90% level. (c) Whether it is desirable to maintain the revenue neutrality existing in the tiered rate structure currently in place. (d) Commission-observed uncertainty around CBL reset and adjustment policy, which may have a chilling effect on customer funded DSM investment. From AMPC s perspective, implementation of, and adjustment to, the current steppedrate has been administratively complex. A significant amount of cooperative work has been invested by both AMPC and BC Hydro. As a result, the issues identified by the BCUC in 2009 have been fully addressed (or are currently before the Commission). Any near-term changes would undercut the value of the effort that has been invested, and jeopardize customer conservation investments made under the current regime. This is particularly so if the stepped rate were to be replaced by a blended rate based on a weighted average of the Tier 1 and Tier 2 rates. Customers who had invested in conservation projects would see anticipated benefits disappear as Tier 1 rates were increased, essentially clawing back the savings they had hoped to achieve by investing in conservation.

17 15 More fundamentally, the stepped rate is functioning as intended. Customers have reduced Tier 2 purchases and must continually reinvest in conservation to keep their purchases below their customer baseline (CBL). Maintaining revenue neutrality is fundamental. This principle provides a guarantee that industrial purchasers do not cross-subsidize other rate classes, and provides a significant degree of confidence that rates will be fair and predictable in the future. No changes should occur in the absence of a relevant fully allocated cost of service (FACOS) study, and a substantial measure of consensus. Earlier concerns that the stepped rate would result in other rate classes subsidizing industrial customers have been addressed by BC Hydro s recent FACOS study, which is attached as Appendix C. Despite the fear that minimizing Tier 2 purchases and achieving the rate s conservation goal would result in under-recovery from industrial customers, and a transfer of costs to other classes, the BC Hydro FACOS study clearly shows that the industrial rate revenue to cost ratio is increasing and that current rates recover a greater portion of the cost of industrial customers service than they have in the past. AMPC expects that this may be in part because, contrary to initial trends established during a market downturn, customers have been consuming significant amounts of Tier 2 electricity over the last two years. Concerning energy intensity rates, AMPC believes it is simply impossible in practice to design rates that cover a variety of customers in different industries and with different vintages that will be fair, or perceived to be fair. IV. CONCLUSIONS Based on the foregoing discussion, AMPC submits that the task force should make the following recommendations to government: 1. Direct BC Hydro to renew its focus on achieving the lowest cost electricity rates that guarantee reliable service, as a single and overarching economic development objective. BC Hydro should stop the use of deferral accounts to cover current period costs, and establish a transparent plan to reduce existing high level deferral accounts to more sustainable levels, possibly by way of financial write-offs. The task force should clearly recognize that government policy under the Clean Energy Act has increased costs to BC Hydro customers, and needs to be changed. The limits on the use of natural gas for generation by BC Hydro must be revisited and removed or lowered substantially. BC Hydro should be managed like a utility, not a social service, and environmental initiatives should be broadly applicable and not narrowly targeted at BC Hydro. BC Hydro should develop a retail access policy to create rate cost discipline and provide customers choice.

18 16 2. BC Hydro, before the BCUC, should develop a universal and principled transmission contribution policy to send transparent, fair price signals, mitigate rate pressure, and accommodate incremental development. 3. There should be a full return to traditional independent utility regulation of BC Hydro by the BCUC: An independent regulator should transparently determine the need for all new facility additions, approve a prudent level of allowed revenues, and determine all of the tariffs that are in effect. Government should continue the existing postage stamp rates and the two-step industrial rate. BC Hydro s FACOS study confirms that the stepped-rate does not cross-subsidize industrial customers at the expense of other customer classes. Government should not implement end-use rates or energy intensity rates.

19 Appendix A Electricity Rates in BC See attached presentation from AMPC, dated January 16, 2013.

20 Electricity Rates in BC Association of Major Power Customers of BC January 16, 2013

21 Where did the electricity market go? Source: ail.cfm?id=6450# 2 Electricity Rates in BC 2012 Overview

22 Domestic sales have not returned to F2008 levels 3 Electricity Rates in BC 2012 Overview

23 Effective industrial rates exceeded market prices since F Electricity Rates in BC 2012 Overview

24 Escalation in rates has been compounded by increases in non energy components 5 Electricity Rates in BC 2012 Overview

25 There is a material gap in market prices and industrial rates 6 Electricity Rates in BC 2012 Overview

26 BC rates are up 24% over 3 years relative to 6% for the rest of Canada (note 3) change City region $/MWh $/MWh $/MWh $/MWh $/MWh $/MWh $/MWh % Montréal, QC Montréal,QC $ $ $ $ $ $ $ $ % Calgary, AB Calgary,AB $ $ $ $ % Charlottetown, PE Charlottetown,PE $ $ $ $ $ $ $ $ % Edmonton, AB Edmonton,AB $ $ $ $ $ $ $ $ % Halifax, NS Halifax,NS $ $ $ $ $ $ $ $ % Moncton, NB Moncton,NB $ $ $ $ $ $ $ $ % Ottawa, ON Ottawa,ON $ $ $ $ $ $ $ $ % Regina, SK Regina,SK $ $ $ $ $ $ $ $ % St. John's, NL St. John's, NL $ $ $ $ $ $ $ $ % Toronto, ON Toronto,ON $ $ $ $ $ $ $ $ % Vancouver, BC Vancouver,BC $ $ $ $ $ $ $ $ % Winnipeg, MB Winnipeg,MB $ $ $ $ $ $ $ $ % Canadian average excluding BC $ $ $ $ $ $ $ $ % Boston, MA Boston,MA $ $ $ $ $ $ $ $ % Chicago, ILL Chicago,ILL $ $ $ $ $ $ $ $ % Detroit, MI Detroit,MI $ $ $ $ $ $ $ $ % Houston, TX Houston,TX $ $ $ $ $ $ $ $ % Miami, FLA Miami,FLA $ $ $ $ $ $ $ $ % Nashville, TN Nashville,TN $ $ $ $ $ $ $ $ % New York, NY New York, NY $ $ $ $ $ $ $ $ % Portland, OR Portland,OR $ $ $ $ $ $ $ $ % San Francisco, CA San Francisco, CA $ $ $ $ $ $ $ $ % Seattle, WA Seattle,WA $ $ $ $ $ $ $ $ % US Average $ $ $ $ $ $ $ $ % BC's ranking Notes 1. source: 2. the rates reflect those in effect on May 1 of the year stated 3. data from BCH 2004/5 and 2005/65 RRA 4. calculations based on 50 MW demand, 30.6 GWh/month, service at 138 kv and a load factor of 85% 7 Electricity Rates in BC 2012 Overview

27 That erosion does not even reflect the impact of programs in other jurisdictions Nova Scotia Load Retention Tariff for Port Hawkesbury Paper at ~$2/MWh over real time market rates Washington State The Bonneville Power Administration and Port Townsend Paper Corporation signed an amendment to the existing power sales contract that provides one of the largest employers on the Olympic peninsula another nine years of low-cost federal power. The amendment extends the term of the contract through September 2022, preserving 300 family wage jobs in a community of 8,300 residents while providing BPA and the Northwest with financial and operational benefits. The agreement provides an economic advantage to producers who compete directly with BC companies. Ontario Northern Industrial Electricity Rate Program $20/MWh rebate up to $20 million/year per customer Northern Ontario, defined as being within the collective territorial Districts of Kenora, Rainy River, Thunder Bay, Cochrane, Algoma, Sudbury, Timiskaming, Nipissing, Manitoulin, and Parry Sound 8 Electricity Rates in BC 2012 Overview