BRITISH COLUMBIA HYDRO AND POWER AUTHORITY AND BRITISH COLUMBIA POWER EXCHANGE CORPORATION ENERGY REMOVAL CERTIFICATE APPLICATION REPORT AND RECOMMENDATIONS to the LIEUTENANT GOVERNOR IN COUNCIL JUNE 30, 1992
FOREWORD The information contained in this document is excerpted from the Report entitled: "Energy Removal Certificate Application, Report and Recommendations to the Lieutenant Governor in Council". For more information about this Report, please contact: The Commission Secretary British Columbia Utilities Commission Box 250, 900 Howe Street Vancouver, B.C. V6Z 2N3 Telephone B.C. Toll Free: 1-800-663-1385 or Telephone Long Distance: (604) 660-4700 Facsimile: (604) 660-1102
EXECUTIVE SUMMARY This summary provides a general overview of the report, highlighting its key findings. For the sake of brevity and readability, less technical language is used and certain details have been omitted. Accordingly, this summary does not form part of the Commission's formal response and readers are referred to the report itself for the complete text. THE APPLICATION B.C. Hydro and POWEREX made a joint Application on April 19, 1991 to the Minister of Energy, Mines and Petroleum Resources for renewal of their Energy Removal Certificate which is currently due to expire on September 30, 1992. As applied for, the new Energy Removal Certificate would allow the Applicants to export electricity from British Columbia until September 30, 1997 at annual limits of: 2,300 MW to the United States and 1,200 MW to Alberta of firm power; 6,000 GW.h of firm energy; and 25,000 GW.h of interruptible energy (less concurrent firm energy). THE HEARING AND ENERGY REMOVAL CERTIFICATE RECOMMENDATION The Minister requested that the Commission review the application in a public hearing according to specific evaluation criteria. The hearing commenced on April 6, 1992 and terminated with final argument on May 14, 1992. The Commission was required to report its findings and recommendations to the Cabinet by June 30, 1992. The Commission recommends the granting of the Energy Removal Certificate, subject to the terms and conditions summarized below. DETERMINATION OF THE ELECTRICITY SURPLUS FOR EXPORT: EFFECT OF EXPORTS ON RELIABILITY AND SECURITY OF SUPPLY The Application is for permission to export short-term surplus electricity; that is, surplus electricity from facilities built to serve domestic customers. In determining B.C. Hydro's short-term firm electricity surplus, the Commission recommends excluding any surplus due to future investments that are avoidable. Using this principle to calculate the removable surplus, three years should be the maximum duration for firm energy sales contracts allowable as short-term exports. With this limitation, and ministerial review of all contracts exceeding one year, the Energy Removal Certificate should not adversely affect reliability and security of electricity supply to British Columbians. (i)
DOMESTIC AND EXPORT MARKETING OF SURPLUS ELECTRICITY The Commission reviewed proposals by the Applicants to replace the current offer mechanism, which allows domestic utilities to view and intercept any export contract. While the Commission favours the proposed Power Exchange Operation, for export sales of less than one year, a number of guidelines are suggested to ensure fair market access for domestic customers. For export sales of greater than one year, the Commission recommends that, although domestic utilities need not view export contracts, they should be provided with price and quantity information and priority access to all major blocks of energy offered for export. The Commission also recommends that approval of all export sales be subject to price tests, ensuring recovery of the incremental cost of production and an allowance for adverse environmental impacts. ENVIRONMENTAL IMPACTS OF EXPORTS-OTHER THAN FROM BURRARD THERMAL For the operation of hydraulic facilities, the Commission found that it is difficult to segregate environmental effects attributable to exports. Available information suggests that the incremental effects of exports will not be significant. However, the Commission suggests the need for further study, and recommends that B. C. Hydro undertake a comprehensive system review of its hydraulic operations with a view to identifying environmental and social impacts of generation and effective mitigation measures. The Energy Removal Certificate may entail the export to the U.S. of significant quantities of coal-generated electricity from Alberta. The Commission recommends that the Applicants be directed to develop, together with other interconnected utilities, a mechanism for incorporating environmental externalities from different energy resources into the price of electricity and into dispatch decisions. To ensure that the environmental impacts of export generation are fully taken into account, the Commission recommends that the Minister of Energy consult with the Minister of Environment in the approval of firm energy export contracts longer than one year. ENVIRONMENTAL IMPACTS OF EXPORTS - THE BURRARD THERMAL PLANT Because of the multiplicity of factors affecting the operating levels of each component of the B.C. Hydro system, the Commission found it difficult to precisely determine the incremental operation of the Burrard Thermal plant for exports. Even if this were known, scientific uncertainties about the effects of air emissions from the plant made it impossible to definitively determine and cost the (ii)
incremental environmental impacts in the Lower Fraser Valley of exports under this Energy Removal Certificate. However, several general observation are possible: exports are likely to lead to an increased use of Burrard, especially in low water years; NO x emissions from Burrard would contribute to the production of ozone in summer months in the Lower Fraser Valley; this ozone has several detrimental effects on the health of humans, animals and vegetation. Applying the precautionary principle, the Commission recommends that until the GVRD and other relevant agencies have achieved consensus on targets and policies for reducing NO x emissions, a cap be placed on the NO x emissions from the Burrard plant during the critical summer period of May to September. Caps are proposed for summer 1993 and 1994. Further caps could be set at levels that meet GVRD objectives, while allowing B.C. Hydro the flexibility to either reduce operation of the plant or undertake emission reduction investments. With these restrictions, the Commission accepts the continued availability of Burrard in support of exports. NET BENEFITS TO THE APPLICANTS AND BRITISH COLUMBIA A benefit cost analysis of this Energy Removal Certificate must rely on estimates of future prices, costs, and quantities, because existing contracts encompass only a small portion of the potential removals. A net revenue estimate suggests significant positive return to both the Applicants and the Province from electricity trade. Including externalities (for a social estimate) is difficult, again because of the early stage of research in the field of environmental costing. However, the Commission's analysis indicates that environmental impacts of air emissions would have to be at the high end of current estimates of environmental externalities before exports that rely on Burrard would lead to negative net benefits for the Province. Also, preliminary calculations, for illustrative purposes, suggest that a seasonal cap on Burrard emissions may be a more cost-effective means of achieving improvement of environmental quality than mandating a pollution control investment at the plant. This is because, unlike most facilities, the plant's value to the B.C. Hydro system is not necessarily dependent upon its full-time operation. (iii)
1 8.0 SUMMARY OF PRINCIPAL CONCLUSIONS AND RECOMMENDATIONS The following summary responds directly to the Terms of Reference provided to the Commission to govern the scope of the B.C. Hydro/POWEREX Energy Removal Certificate ("ERC") public hearing. Other recommendations, of secondary importance, appear in the text where the issues are discussed; they appear in bold face for ease of identification. Recommendations appearing in this summary may be abridged from those appearing in the body of the report. In its introduction (Chapter 1.0) the Commission notes the very large number of export and generation related issues currently under review by a range of public agencies and by the industry itself. The following recommendations attempt to provide short-term decision-making guidance within the framework of longer-term changes facing the electric generating industry. 8.1 Net Benefits The Commission concludes that net benefits to both the Province and the Applicants from the export of electrical energy and related services are positive and significant. The magnitude of these benefits, through the projected term of the ERC, under a number of different scenarios, is estimated in Chapter 7.0 and is summarized in Section 8.13 below. 8.2 Recommended ERC Term The Commission concludes that the length of an ERC need not necessarily relate to the term of export contracts signed within the conditions of the ERC. The length of an ERC is related more properly to the need for periodic review of policies related to short-term exports. The Commission recommends that the ERC requested by the Applicants, extending to September 30, 1997, be granted. It is recommended that the Certificate itself be qualified with respect to specific issues, as outlined in the following paragraphs and in the body of this report. 8.3 Electricity Export Limits B.C. Hydro/POWEREX have applied for electricity exports up to annual upper limits of: Firm Power: 2,300 MW to the USA 1,200 MW to Alberta Firm Energy: 6,000 GW.h Interruptible Energy: 25,000 GW.h less concurrent firm exports
2 The power (capacity) limit is defined by the capability of provincial boundary interties. Energy limits represent the upper bound of availability under the most favourable river run-off and market conditions. The Commission believes it is important to retain maximum flexibility for B.C. Hydro/POWEREX to respond to high water and market conditions as they occur. Constraints on exports relate much more closely to low water conditions; critical low water governs many of the Applicants' export decisions. The Commission recommends that the annual upper limits to electricity exports be retained at the levels proposed by the Applicants. 8.4 Reliability and Security The reliability and security of domestic electricity supplies are significantly enhanced by the interconnection of British Columbian generating sources with U.S. and Alberta systems through coordination and emergency support agreements and Alberta reserve sharing. The Commission sees the greatest threat to reliability and security of electrical energy supply to B.C. customers coming from possible over-commitment of resources to export through the signing of firm contracts covering a term beyond the range of confident prediction of supply sources and water conditions. The Commission proposes to limit this danger by limiting the maximum term of firm energy contracts to three years and by requiring specific Ministry approval of those over one year's duration (Sections 8.6 and 8.8.1, below). The Commission does not believe export contracts for interruptible energy pose a threat to the reliability and security of domestic supplies of electricity and proposes fewer constraints on them. 8.5 Determining Removable Firm Surplus The procedure currently in place for the determination of removable firm surplus takes the firm energy which can be supplied to the B.C. Hydro system in any year under the lowest historic four-year streamflow conditions (1942-46) and subtracts forecast domestic load requirements for each year of the requested Licence. Interruptible surplus is energy surplus to domestic demand primarily due to water flows above critical low water conditions, and can occur at any time. The Commission recommends that, in future, in making the short-term firm energy surplus calculation any supply resource that is not yet committed (i.e. avoidable) not be included in the calculation. It is recommended that
3 this same procedure be used to determine the short-term time-frame to which the maximum duration of firm export contracts under the ERC should be limited. 8.6 Determining "Short-Term" Time-Frame B.C. Hydro's own estimation of the removable energy surplus under critical water, during the five-year term of the ERC, shows heavy reliance on non-hydro resources, some not yet committed. The Commission believes that only those resources already in place or already committed to serve domestic load should properly be considered when determining "removable energy surplus". When this definition is applied to the B.C. Hydro system, firm surplus becomes a net deficit by 1995/96. The Commission recommends that the Applicants' short-term time-frame be defined as no more than a maximum of three years. Firm energy sales contracts longer than three years in duration should be referred to as long-term contracts because they will generally require additional investment commitments. The Commission recommends that export contracts for firm energy in excess of three years should not be permitted under this ERC. 8.7 Marketing Surplus Electricity in the One Year Time-Frame Energy surpluses, both firm and interruptible, can be reliably determined, with low risk, during the short one-year time-horizon. An export market exists for such surplus and the Applicants believe this market can be enhanced by the institution of a Power Exchange Operation ("PEO"). The Commission concurs in the belief that the PEO concept has merit, and that it could lead to a more active short-term trade (less than one year) with improved financial returns to the Applicants and the Province.
4 The Commission recommends, subject to specific constraints set out in Chapter 4.0, that the Minister give favourable consideration to the establishment of the PEO which is currently the subject of a separate Application to the Ministry of Energy. Furthermore, the Commission recommends that export contracts of less than one year's duration, whether conducted through the PEO or otherwise, not be subject to Ministerial approval. 8.8 Marketing Surplus Electricity in the One to Three Year Term 8.8.1 Firm Energy Sales The Commission believes that sales of surplus firm energy carry a greater risk to the security of domestic supply as the term extends out towards the proposed three-year limit. Nevertheless, firm energy sales are attractive from a revenue point of view and the Commission believes such contracts can safely continue to be negotiated under appropriate conditions, subject to Ministry review. The Commission recommends that all firm energy contracts in the one to three year term be made subject to approval by the Ministry of Energy and that the request for approval be required to demonstrate that the sale will not jeopardize domestic supply; will meet a minimum price test; will provide domestic interconnected utilities with at least fair market access and will not involve unacceptable environmental impacts. 8.8.2 Interruptible Energy Sales The Commission sees no reason to limit interruptible sales contracts to a three-year term although contracts longer than three years are considered unlikely. The Commission recommends that interruptible sales over one year and up to five years be permitted subject to minimum price tests, fair market access to domestic utilities, and subject in all cases to Ministry approval.
5 8.9 Priority For Domestic Utilities The Commission believes that the current offer mechanism or "right of interception" for interconnected domestic utilities is inappropriate if the PEO is to be instituted for electricity trade of less than one year's duration. The Commission recommends, for trade of less than one year's duration, particularly if executed through the proposed PEO, that a fair market access policy replace the right of interception for domestic utilities. The Commission believes fair market access can be assured by specific changes to PEO operational procedures, details of which are given in Chapter 4.0. The Commission believes that, with improved information flow to interconnected domestic utilities, fair market access conditions could be created for blocks of energy trading in the one to three year term (firm) or one to five year term (interruptible). The Commission recommends that for trade of this nature the Applicants no longer be required to make specific offers to interconnected domestic utilities. Domestic utilities should, however, be provided with price and quantity information and with priority access to all blocks of energy offered for export, upon their expression of serious interest. Alternatively, a "right of interception" could be considered for contracts over one year by incorporation of clauses similar to Clauses 8 and 12 of the existing ERC.
6 8.10 Operating Procedures and the Environmental Aspects of Energy Removals 8.10.1 Generation from Hydraulic Systems Incremental effects of export trade on B.C. Hydro reservoirs and connecting river systems are generally small and are normally over-shadowed by total system operation impacts for domestic needs. In making dispatch decisions, B.C. Hydro generally attempts to consider environmental impacts in a qualitative way and to adjust its dispatch accordingly. However, B.C. Hydro makes no attempt to formally evaluate the cost of these multiple impacts in its system operations models. U.S. utilities operating on the lower Columbia (below the Canadian border) are currently carrying out a System Operation Review with the objective of modelling system operations so as to formally evaluate environmental costs associated with dispatch decisions. It is recommended (Chapter 5.0) that B.C. Hydro be required to move in the same direction as the U.S. utilities so as to more fully account for the environmental impact of dispatch decisions. 8.10.2 Generation from Alberta Sources Alberta generation can provide the source for some of British Columbia's export trade. Alberta energy purchases by the Applicants are normally supplied from coal-fired resources. To the extent that this generation may be substituted for gas-fired thermal generation in the importing region, there could be a net contribution of carbon dioxide, sulphur dioxide, and particulates to the North American environment. In contrast, when water-based exports are occurring there is an environmental benefit as such exports usually displace U.S. thermal generation. 8.10.3 Costing Incremental Environmental Effects Related to Export Generation___________ Currently, B.C. Hydro does not attempt to specifically cost environmental effects related to generation from any of its sources. No other member utility in the Western Systems Power Pool yet applies environmental costing to dispatch of its various generating sources.
7 The Commission recommends that B.C. Hydro move towards the identification and incorporation of environmental costs in its dispatch decisions. Until such time as this is universally achieved, the Commission recommends that a minimum margin of 0.3 cents per kW.h be incorporated into POWEREX's export supply price to cover unidentified environmental effects of incremental export generation within B.C. 8.10.4 Export Contract Review The Commission suggests that a more complete review of environmental impacts of electricity exports would result from more formal participation by the Ministry of Environment. The Commission recommends that consideration be given to approval of electric energy export contracts by the Minister of Energy in consultation with the Minister of Environment. 8.11 The Role of the Burrard Thermal Generating Station The 912.5 MW Burrard gas-fired thermal generation station is capable of contributing up to 5,520 GW.h per year to B.C. Hydro's integrated system. In years when water supplies to the hydroelectric system are well above average the station may not operate at all. When runoff is weak the station is likely to generate at a relatively high level. B.C. Hydro predicts an average level of operation of 2,500 GW.h per year during the period of the ERC. It is impossible to predict how much of this generation will be in support of exports; however, Burrard is likely to be used to "firm up" export contracts if and when such contracts are negotiated. Burrard contributes to system loads outside the winter season by generating from low-cost valley gas to supplement hydroelectric generation and a significant part of this summer generation may contribute to exports. 8.12 Environmental Impacts of Burrard The primary environmental impact from Burrard is on the Lower Fraser Valley ("LFV") airshed. Nitrous oxides emitted from the plant react with volatile organic compounds in the presence of sunlight to create ground level ozone. At higher concentrations ozone can be damaging to the respiratory tract of humans and can affect crop yields.
8 The Burrard plant is the next largest point source of NO x , after the cement plants, in the LFV airshed. When operating at full load, it contributes between two and four percent of the total airshed emissions of NO x . Ozone concentrations are not linearly related to NO x emissions. They vary with meteorological conditions; episodes of high concentrations occur most frequently in the summer months due to elevated temperatures, longer hours of sunlight, temperature inversions which limit the mixing depth, and light winds. Daily on-shore summer breezes concentrate the ozone in the central Fraser Valley where the effect is most marked. 8.12.1 Permitted Emission Limits Pollutant emissions from Burrard are governed by a permit issued by the District Director, Air Quality and Source Control, of the GVRD. Heretofore, NO x emissions have been limited to 170 mg/m 3 from each stack source, at three percent oxygen. Burrard's emission permit expired on April 30, 1992 (during the hearing) and was renewed at the current levels, but B.C. Hydro was placed on notice that they would be required to install NO x reduction equipment to reduce these emissions to 55 mg/m 3 as soon as possible after completion of B.C. Hydro's ongoing "Burrard Utilization Study". Evidence at the hearing indicated a cost of $45 to $100 million to install MACT or SCR technology (see Chapter 6.0) on all units, which would achieve the lower level required. The air emissions permit for Burrard has an over-riding ozone episode control clause requiring the plant to shut down its operation when a high ozone episode is seen to be building. 8.12.2 The GVRD Air Quality Management Plan ("AQMP") Stage 2 of the GVRD AQMP was published during the ERC hearing and filed in evidence. The plan has a target of a 50 percent reduction in thermal generating station point source emissions, below current levels by the year 1995. Different sources are assigned differing rates of reduction related to the industry's state of emissions reduction technology. The Stage 2 AQMP for Burrard translates to a plant limit of 1,100 tonnes per year of NO x by 1995 and 660 tonnes per year by the year 2005. These figures compare with a current annual emission rate of 2,200 tonnes with the plant operating at maximum annual capability of 5,520 GW.h per year. This energy output capability is not distributed evenly throughout the year. For technical reasons, related to maintenance and to the availability of lower-cost summer gas, the energy rate is highest during the summer months.
9 The Commission is of the view that limiting Burrard emissions by means of an annual, monthly or daily plant "cap" is preferable to the GVRD's current method of limiting emissions from each individual stack. The ultimate objective is to limit the tonnage emitted: how the reduction is achieved should be left to the industry itself. Determination of the most cost-effective way to reduce emissions at Burrard is the primary purpose of the Burrard Utilization Study now underway. Limiting emissions from each stack and tying the emission level to specific technology minimizes any opportunity for the utility to exercise ingenuity in finding the most cost-effective solution. The Commission urges the Ministry of Energy and the Ministry of Environment to work with the GVRD District Director in considering the NO x "cap" concept for Burrard in setting emission limits in the future. 8.12.3 Reducing Burrard's Contribution to Critical Summer Ozone Formation__ After listening to the evidence on summer ozone impacts in the Lower Fraser Valley, the Commission is satisfied that a serious problem exists. While Burrard contributes less than four percent of the airshed's NO x on an annual (average) basis, the fact remains that it is the second largest point source in the valley and that its production from lower-cost valley gas may tend to be high in the summer months when the ozone problem is at its worst. While the precise plant contribution to exports is impossible to determine, Burrard does unquestionably contribute to the firming of summer export contracts. The Commission concludes that Burrard may be used in support of exports, subject to reduction in NO x emissions during the period May 1st to September 30th, and recommends that these constraints be made a condition of the requested ERC. As an interim measure, until the Burrard Utilization Study is complete and a clear program for NO x control is in place, the Commission proposes a two -step cap on the tonnage of NO x emissions during the period May 1st to September 30th. The Commission recommends that B.C. Hydro be required to cap its NO x emissions from May 1st to September 30th at the following levels:
10 Summer 1993 - Daily Cap: 6.03 tonnes NO x (This corresponds to an annual rate of 2,200 tonnes, evenly distributed on a daily basis) Summer 1994 - Daily Cap: 5.02 tonnes NO x (This corresponds to an annual rate of 1,833 tonnes, evenly distributed on a daily basis) It should be noted that an annual cap at the proposed 1994 rate was offered to the GVRD by B.C. Hydro, for the 1992 calendar year only, but this proffered reduction was not pursued. The financial implications of these caps and of the ultimate 1995 NO x emission level required by the GVRD's Stage 2 Air Quality Management Plan are provided in Chapter 7.0 and in Section 8.13 below. 8.12.4 Air Emissions Modelling An air emissions model for the Lower Fraser Valley, capable of precisely identifying Burrard's role in ozone formation, has not yet been applied. Sophisticated reactive plume models do exist, although the complex topography and meteorology of the Fraser Valley complicate their application to this area. The Commission concludes that up-to-date information on the dispersion and the ultimate impact of the Burrard plume is not now available but is capable of being generated. The Commission recommends that the Applicants be required to provide information on the separate effects of Burrard as an embedded source within a regional oxidant model. It is further recommended that, to achieve this objective, the Applicants collaborate with the GVRD, and federal and provincial government agencies in their ongoing modelling activities. 8.13 Quantifying Net Benefits The Commission has attempted to evaluate the annual net financial benefits to the Applicants and to the Province from the proposed removals under four different scenarios: (i) Under existing air emissions permits at Burrard (Base Case).
11 (ii) With application of the Commission's recommended 1993 cap on Burrard's summer emissions. (iii) With application of the Commission's recommended 1994 cap on Burrard's summer emissions. (iv) With emissions controlled to the 1995 GVRD Stage 2 Air Quality Management Plan level. The above analyses, reported in Chapter 7.0, are based on B.C. Hydro's projections, modified as necessary. They examine a range of values covering low water, average water and high run-off conditions. The figures include no allowance for incremental environmental impacts (see Section 7.4.2). (a) Base Case (Existing Emission Conditions) The Commission estimates annual net revenue to the Applicants from firm and interruptible energy exports to be: Net Revenue to Applicants Low Water Average Water High Water (Millions of dollars) Firm Energy 2 15 107 Interruptible Energy __6 __20 __21 Total 8 35 128 Water rentals accruing to the Province would add to the above net financial benefits, from zero (low water year) to $45 million (high water year). Other benefits of electricity trade include coordination with Bonneville Power Administration and Alberta utilities, storage, equichange and other services. The Commission estimates quantifiable net benefits of this type at approximately $25 million per year. (b) 1993 Capped Case The net effect of imposing the proposed NO x emissions cap on Burrard is to reduce the above-described net annual financial benefit by approximately $3 million in an average water year.
12 (c) 1994 Capped Case The net effect of applying the recommended second stage cap in 1994 is to reduce the base case net financial benefits by about $5 million in an average water year. (d) The 1995 Stage 2 GVRD Air Quality Management Plan NO x Level Because of the greater difficulty in selecting underlying assumptions, the figures for this case are less certain. However, they are believed to provide a reasonable estimate of the impact of the full emissions abatement required by the GVRD for 1995. The result, if there is no change in abatement technology, would be to still further reduce the estimated net revenue from exports under average water conditions from the current level of approximately $35 million per year to the Applicants to some $26 million per year, resulting in an annual financial loss of about $9 million. The range of options available to the Applicants to mitigate the above losses has not been fully explored, and hence it may be reasonable to expect actual losses to be somewhat less than the estimates cited above. The Commission's analysis of emission caps and abatement technology indicates that the social cost of air emissions would have to be at the high end of current estimates of environmental externality in North America before exports that rely on Burrard would lead to negative net benefits for the Province. Further, illustrative calculations suggest that a cap on Burrard emissions may be a more cost effective means of achieving targetted emission reductions, as compared to mandating abatement by a technological retrofit to the plant. This is because, unlike most facilities, the plant's value to the B.C. Hydro system is not necessarily dependent upon its full-time operation.
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