Canada: Energy @ Gowlings - September 2004

Last Updated: September 21 2004

Edited by Paul Harricks


  • Discussions Begin to Restart Bruce Power's Remaining Two Units
  • National Energy Board Issues Market Report
  • Regulated Ontario Price Plan in the Making
  • LNG Proposals Popping Up All Over
  • Final Tenders Submitted for B.C. Hydro Vancouver Island Call
  • Natural Gas Forum Update - Notice of Technical Consultation
  • Nuclear Microbatteries
  • Supply Chain Capabilities in the Canadian Wind Power Industry
  • Electricity Distributor Conservation and Demand Management Activities
  • McDonald's Makes Green Power Commitment in Alberta
  • The EUB Tells the AESO to do More Work Before it Makes A Decision on the Southwestern Alberta 240 kV Transmission Line
  • RP-2004-0188 2006 Electricity Distribution Rates (2006 EDR)

Discussions Begin To Restart Bruce Power's Remaining Two Units

The Ontario Government announced on September 8 that it was beginning discussions with Bruce Power to potentially restart the remaining two units at Bruce Power's nuclear facility in Kincardine, Ontario.

There are eight nuclear reactors at the facility. Bruce A Unit 3 was restarted after refurbishment in 2003, followed by Unit 4 in 2004. All four Bruce B units are operational.

Bruce Power is a private power company with a contract to run the Bruce facility until 2018.

Ontario Energy Minister Dwight Duncan said that Bruce Power has a good track record so far with bringing reactors back on stream, on time and on budget, a far cry from Ontario Power Generation's mess at the Pickering nuclear facility east of Toronto.

"The potential restart of Units 1 and 2 at the Bruce facility would result in an additional 1,540 megawatts (MW) of electricity generating capacity, which is enough to power over one million homes across Ontario. Restarting these units would also potentially replace over 20 per cent of our current coal capacity and related harmful emissions, which means cleaner air and a better quality of life for Ontarians," said Duncan.

The restart of these two units would represent another significant step towards meeting the government's commitment to replace coal-fired generation in Ontario.

The government has hired David Santangeli, Managing Director of Energy Fundamentals Group Inc. (investment firm specializing in energy infrastructure) to broker the deal and lead a team that will advise them on the potential for negotiating the best deal.

Duncan Hawthorne, chief executive of Bruce Power wouldn't put a firm figure on the job but did say that it is significantly north of $2 billion.

National Energy Board Issues Market Report

The National Energy Board (NEB) recently released an energy market assessment report entitled Looking Ahead to 2010 — Natural Gas Markets in Transition. The report summarizes the feedback and recommendations received by the NEB during a nationwide consultation on the future of natural gas markets in Canada. The report also discusses specific actions the NEB will take in response to these recommendations.

In preparing the report, the NEB sponsored eight roundtable sessions in major Canadian cities to examine how natural gas markets may evolve to the end of the decade. Participants agreed that a tight balance between natural gas supply and demand will likely continue in the next few years until new supply can be developed or sufficient adjustments can be made in new technology or energy consumption. Participants were asked to identify potential actions that could be taken by regulators, governments and market participants to facilitate a smooth transition in the natural gas market during this period.

For more information and to view the report, please "What's New" at the NEB Web site:

Regulated Ontario Price Plan In The Making

Currently, low volume and designated electricity consumers in Ontario are subject to a tiered pricing structure of 4.7¢/kWh and 5.5¢/kWh for the electricity commodity portion of their bill. Legislation requires the Ontario Energy Board (OEB) to establish a longer term regulated price plan by no later than May 1, 2005. Bill 100 (an Act to amend the Electricity Act, 1998 and the Ontario Energy Board, 1998 and to make consequential amendments to other Acts) contemplates an annual regulated price plan.

The new regulated price plan (RPP) will replace the current "two-tiered" pricing. The RPP is expected to serve as a price schedule that specified consumers can choose as an alternative to, or in conjunction with, a retailer electricity contract. Consumers be eligible for the RPP will be defined by regulation. The RPP development process will ultimately result in a new code that replaces the existing Standard Supply Service Code.

The OEB has engaged consultants to assist it in developing the RPP, which has a delivery date of spring 2005. As a first step in the RPP development process, the OEB held a consultation session on September 10, 2004. Working groups will now be created to assist the OEB staff in developing the RPP. A draft RPP Code will then be prepared for review and comment.

OEB staff have prepared an issues paper (dated August 23, 2004) that sets out the policy context of the RPP project, contains a proposed conceptual approach and identifies issues to be addressed. The issues discussed in the paper are not exhaustive, but rather are intended to facilitate discussion in relation to identifying issues that should be addressed by the OEB as it proceeds. High level issues identified in the paper include:

  • achieving the best balance between the conflicting objectives of "price stability" and "cost reflective pricing," while incenting conservation;
  • hybrid market price blending (recognizing that the market will be supplied by a variety of sources including contract supply by non-utility generators, Request for Proposal participants, and Ontario Power Generation, and recognizing the variety of pricing methods to consider such as market price, price blending, and customer class issues); and
  • settlement issues (for example, who should hold price variances and what are the implications where a retailer contract is involved); and (d) policy issues (for example, what best supports conservation and demand-side management). The OEB anticipates that stakeholders and other interested parties will raise additional issues and concerns for consideration.

For additional information and to view the issues paper, please see the OEB's Web site at:

LNG Proposals Popping Up All Over

Proposals for Liquefied Natural Gas (LNG) facilities are becoming an increasingly common feature on the energy landscape.

LNG is created by chilling gas to very low temperatures and concentrating the energy into far smaller volumes than it would occupy in a gaseous state. It currently has limited use in Canada, principally to meet peak requirements.

Recently, proposals to import LNG into Canada have been advanced for such diverse locations as Prince Rupert, British Columbia, the Strait of Canso in Nova Scotia, the Bay of Fundy in New Brunswick and a couple of locations on the St. Lawrence River in Québec. Other proposals exist in British Columbia and Nova Scotia

The Strait of Canso project was recently in the news since the project proponent, Access Northeast Energy Inc., was acquired by Anadarko Petroleum Corp. of Houston. Access Northeast had brought the project through a number of planning and regulatory steps to the point where Anadarko clearly felt it represented a worthwhile project to acquire. Plans at the moment call for regasification of up to one billion cubic feet of gas a day which would be shipped to northeast U.S. markets via the Maritimes & Northeast Pipeline.

The other Nova Scotia proposal is by Keltic Petrochemicals, to be located at Goldboro, site of the processing plant which feeds into Maritimes & Northeast.

The chief proponent of the Bay of Fundy project is Irving Oil Limited. It too would need to rely on Maritimes & Northeast to carry gas to markets.

The first Québec project to be announced is sponsored by Enbridge Inc., Gaz Métropolitain and Gaz de France. It would be situated near Québec City and supply approximately 500 million cubic feet a day of gas into Québec and possibly for export, likely to New England.

The other proposal in Québec is sponsored jointly by TransCanada PipeLines Limited and Petro-Canada. Located farther down the St. Lawrence River near Riviére-du-Loup, it too proposes gasification of approximately 500 million cubic feet a day.

The Prince Rupert project would import gas from Asia or Alaska. At the moment, Prince Rupert is connected to the North American grid via an existing and comparatively small pipeline extending from the Duke Transmission (Westcoast) facilities near Prince George.

The proposals are a reflection of declining gas reserves in North America coupled with an ever-increasing demand for the commodity.

Final Tenders Submitted For B.C. Hydro Vancouver Island Call

In October 2003, B.C. Hydro issued its Vancouver Island Call for Tenders (VI CFT) to address an anticipated electricity supply shortfall on Vancouver Island. This call invited private sector developers to submit proposals for up to 300 MW of new, dependable capacity on Vancouver Island. Individual projects had to be at least 25 MW in size and be in commercial operation by 2007.

On November 17, 2003, B.C. Hydro announced that 23 bidders had registered to participate in VI CFT. These bidders were required to submit pre-qualification submissions, with successful pre-qualifiers then being invited to submit tenders. Of the 23 bidders registering, 14 bidders made pre-qualification submissions. Eleven of these 14 bidders pre-qualified on April 29, 2004. These 11 bidders represented 22 projects from a diversity of energy sources, including biomass, natural gas and water. Half of the pre-qualified bidders were bidding on the basis of acquiring B.C. Hydro's Duke Point site.

On August 16, 2004, B.C. Hydro announced that, of the 11 pre-qualified bidders, only six had chosen to submit tenders to the VI CFT. Of the six bidders, three are tied to B.C. Hydro's Duke Point project and three projects, being Green Island Energy's biomass project in Gold River, Calpine's natural gas project in Campbell River and EPCOR's natural gas project in Ladysmith, are independent projects.

B.C. Hydro will now review the tenders, with the final awards also being reviewed by the British Columbia Utilities Commission.

The successful projects are anticipated to be announced by late October 2004 and electricity purchase agreements awarded at that time.

Natural Gas Forum Update - Notice Of Technical Consultation

On September 3, 2004, the Ontario Energy Board (OEB) issued a letter to update Natural Gas Forum (NGF) participants on the process for the OEB's upcoming oral consultation phase. As part of the NGF initiative, the OEB sponsored the following discussion papers, prepared by ICF Consulting Canada Inc.: (1) System Supply in Ontario; (2) Storage in Ontario; and (3) Rate Regulation in Ontario (System Supply and Rate Regulation are posted on the OEB's Web site and Storage is expected to be available shortly). These papers are the starting point for discussion at these technical consultations.

The consultations are scheduled to take place from September 27 to October 5. Interested parties must register in advance by September 13, 2004.

For more information and to view the discussion papers, please see the OEB's Web site:

Nuclear Microbatteries

The number of devices that use batteries as a power source continues to increase. Moreover, many of these devices are becoming increasingly miniaturized, and are either mobile (such as PDAs, digital cameras, or GPS devices), or placed in remote locations (such as environmental sensors). Improvements in traditional chemical battery technology have not kept pace with the improvements in the devices that use them, and so the need to replace or frequently recharge the batteries has become a significant limiting factor in the continuing development and use of these devices. So the search is on to find alternative micropower sources.

Fuels cells are being heralded as one alternative to traditional chemical batteries. Fuel cells create electricity using hydrogen and hydrocarbon fuels such as propane, methane, and gasoline as the energy source. However, this approach also has its own limitations. The fuels have relatively low energy densities, only about 5 - 10 times that of the best lithium-ion batteries. Another is that the fuel must also be regularly replenished, and finally the containers that hold the fuel becomes a limiting factor when trying to reduce their size.

Other micropower sources that are being investigated are various kinds of nuclear microbatteries. There are a number of different ways to convert the nuclear energy to electrical energy even on the microscale. Nuclear microbatteries are not miniature nuclear reactors, and they do not involve either fission or fusion processes. Instead, the energy comes from high-energy particles spontaneously emitted by radioactive isotopes. Nuclear microbatteries present their own problems such as safety, efficiency and cost. However, research is well under way to solve these problems and, while they are not expected to replace chemical batteries in the near future, they may well soon serve as a supplement to them in a wide range of devices.

Supply Chain Capabilities In The Canadian Wind Power Industry

The Canadian Wind Energy Association (CanWEA) has just announced that Industry Canada has taken up a suggestion from CanWEA and will launch a study of "Supply Chain Capabilities in the Canadian Wind Power Industry." As announced, the study will focus on component manufacturing, assembly, site specific engineering, installation, maintenance and repair for grid connected, utility-size (600kw and larger) wind turbines.

The study objectives include:

  • identifying current and potential manufacturing capabilities in Canada;
  • identifying potential Canadian suppliers of component parts to the Canadian wind power manufacturing industry supply chain who are presently working in other manufacturing industries;
  • assess and compare advantages and disadvantages for manufacturers to locate in Canada, identifying opportunities for foreign investment through joint ventures or licensing arrangements and other mechanisms to promote technology transfers between market leaders and Canadian firms who are either already in the industry or considering entering it;
  • providing suggestions on how to attract further investment in manufacturing; and
  • identifying regional distribution opportunities and potential emerging markets in Canada that are well positioned to satisfy key Canadian and U.S. markets.

Electricity Distributor Conservation And Demand Management Activities

On May 31, 2004, the Minister of Energy granted electricity distributors permission to apply to the Ontario Energy Board (OEB) for permission to establish deferral accounts to track expenditures on conservation and demand management initiatives. Applications could be made in advance of the distributors' ability to recover the costs through the next instalment of the allowable return on equity in March, 2005. On July 16, 2004, the OEB issued its Preliminary Guidelines for Distribution Conservation and Demand Management Activities and set out the process for distributors to apply for deferral accounts. The guidelines are set in the context of Bill 100 and its promotion of a conservation culture. The guidelines cover the following areas: selection of initiatives (for example, smart metering); regulatory treatment; investments; cost effectiveness; cost allocation; monitoring and evaluation; and implementation.

Some distributors have expressed concern over the lack of certainty of recovering costs incurred to plan, deliver, and evaluate conservation and demand management activities. Some have indicated a gap in knowledge regarding the kind of activities to pursue or where to find information. In response, the OEB issued an Information Bulletin (dated August 30, 2004) to provide suggestions of activities and information resources to distributors. In addition, the bulletin notes that it will post requests from distributors for deferral accounts on its Web site for reference to ideas on potential initiatives.

For more information and to view the information bulletin, please see the OEB's Web site at:

Mcdonald's Makes Green Power Commitment In Alberta

McDonald's Canada owner-operator, Max Pasley Enterprise Ltd., and ENMAX Corporation announced on August 16 an agreement that would supply one quarter of the energy needs of 33 McDonald's stores in Calgary, Red Deer and Lethbridge with electricity supplied from wind-generation.

ENMAX Energy (a subsidiary of ENMAX), will provide the green power through its Greenmax program. The power will come from wind farms in southern Alberta including McBride Lake, Canada's largest wind farm (ENMAX owns 50 per cent).

ENMAX Energy's Greenmax program was the first Canadian utility to give customers the option to support the development of wind-generated power in 1998 and is one of the larest green power marketing programs in North America. The program has over 10,000 residential customers and about 200 commercial customers.

The EUB Tells The AESO To Do More Work Before It Makes A Decision On The Southwestern Alberta 240 KV Transmission Line

The Alberta Energy & Utilities Board (EUB) issued Decision 2004-075 on September 7, 2004 in response to the Alberta Electric System Operators (AESO) Needs Identification Document Application for a 240-kV transmission development in Southwestern Alberta (the SW Transmission System). The EUB decided to refer the application back to AESO to more fully assess and describe existing constraints on the SW Transmission System and to more fully assess and describe in the application upgrade alternatives to address existing constraints.

The EUB set out certain matters that the AESO must detail in its revised application and stated that even though Alberta Regulation AR 174/2004, the Transmission Regulation passed pursuant to the Electric Utilities Act, was passed after the close of the hearing of the Needs Identification Document Application, the AESO must now take the opportunity to have regard to this new regulation in its revised application. AR 174/2004 provides that when the system operator prepares a needs identification document, in addition to the requirements found in section 34(1) of the Electric Utilities Act, the document must describe among other things the timing and nature of the need, an assessment of current transmission system capability, the planning criteria, a 10-year forecast of the load on the interconnected electric system, a 10-year forecast of generation capacity, and the technical and economic comparison of the options considered as detailed in the regulation.

The EUB went on to provide that if AESO proposes that adoption of its initially proposed transmission solution, presumably after it has completed its assessment of existing constraints and upgrade alternatives, it must further justify as to why it proposes system access greater than that contemplated by the Transmission Development Policy and the new Transmission Regulation. The EUB has advised that it will issue a further report giving more reasons for its decision in due course and perhaps with that further report there will be clarity on why the EUB has decided in the manner it has in this instance. In the meantime wind power operators hoping to gain access to the transmission system face yet more delays.

RP-2004-0188 2006 Electricity Distribution Rates (2006 EDR)

On July 6 and 7, 2004, the Ontario Energy Board (OEB) began the process to establish electricity distribution rates for the 2006 rate year (2006 EDR) by holding an informal consultation on the rate-setting process. The OEB canvassed the parties on the issues which should be addressed in this proceeding and reviewed the submissions made subsequent to the consultation. The OEB is now prepared to establish the processes by which it intends to proceed.

The objective of the 2006 EDR project is to establish the new revenue requirements to be recovered in 2006 rates. The OEB will also consider specific proposals for modifying rate design to accommodate changes in the electricity market. These new policies will be set out in a revised Rate Handbook which is expected to be issued by March 2005.

The OEB expects comprehensive cost allocation and rate design to be implemented for the 2007 rate year. This is intended to allow time for load data collection and consideration of cost allocation principles and models to be developed. It will also allow parties to consider rate design issues related to the smart metering initiative.

There are a number of initiatives, such as smart metering and demand side management which may affect 2005 and 2006 rates. Although these will form separate initiatives, the OEB will provide opportunity for the cost and rate-setting impacts of these programs to be considered in 2006 EDR.

The Process

The Board proposes four steps in the 2006 EDR rate-setting process: 1) Issues discussion; 2) Working groups; 3) Alternate dispute resolution (ADR); and 4) Hearing.

1. Issues

In the July 6 and 7 consultation, OEB staff solicited input from participants on a preliminary issues list. A subsequent Issues Conference led by OEB staff was scheduled for September 8 and September 9, the purpose of which was to develop the following four lists for presentation to the Board on Issues Day: 1) issues that all agree should be included; 2) issues whose inclusion on the issues list; 3) issues that, if included, can be resolved through working groups; and 4) issues that, if included, are highly contentious and unlikely to be resolved through the working group process.

2. Working groups

OEB staff has tentatively identified five separate working groups to be established to develop proposals and draft material for incorporation into the Handbook: 1) Comparators; 2) Rate Base, Operating Expense and Working Capital Allowance; 3) Financial Parameters; 4) Taxes/Payments in Lieu of Taxes and Accounting Matters; and 5) Rate Design. Staff will consolidate the work of these groups and provide an initial draft Handbook for review of all parties in October.

3. ADR

An Alternative Dispute Resolution session will be convened in November to allow the parties to discuss and reach an agreement on: 1) issues not resolved during the working group process; and 2) issues that were designated as requiring hearing before the Board.

4. Hearing

The OEB will receive submissions from parties on issues that were discussed through the working group process.

All licensed electricity distributors will be registered as parties to the proceeding and will be provided notification through the designated contact provided their most recent licence application.

For more information, please see the OEB's Web site at

The content of this article is intended to provide a general guide to the subject matter. Specialist advice should be sought about your specific circumstances.

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