Canada: Energy @ Gowlings – January 2007

Edited by Paul Harricks

• OEB Issues Final Report on the Review of the OPA's IPSP

• IESO Issues 18-Month Outlook

• Market Surveillance Panel Releases Electricity Market Monitoring Report

• British Columbia Transmission Corporation to Invest $3.2 Billion in Advanced Energy Network

• European Commission Announces New Energy Policy

The Ontario Energy Board (OEB) has issued its final report on the review of the Ontario Power Authority's (OPA) Integrated Power System Plan (IPSP). The Electricity Act, 1998 (Act) states that the OPA is responsible for developing the IPSP and an adequate procurement process for managing the province's electricity supply, capacity and demand in accordance with the IPSP. The Government's direction on the supply mix is to be included in the IPSP. More information regarding the directive and supply mix can be found in the June 19, 2006 issue of energy@gowlings and the January 23, 2006 Special Edition of energy@gowlings.

The Report notes that the following fundamentals underlie the statutory framework that governs the IPSP:

• The Government, and not the OEB or the OPA, is responsible for articulating the goals that the IPSP is to assist in achieving;

• Those goals go beyond simply ensuring that supply is adequate to meet demand, and the IPSP in that sense is a plan whose scope and purpose is different from that of other, more traditional power system plans; and

• The OPA, not the OEB, has the statutory role of developing the IPSP.

The OEB's mandate is to "ensure that the IPSP complies with the IPSP Directives and that it is economically prudent and cost effective." Based upon this mandate, the Report addresses principles relating to the following:

• The Supply Mix Directive

• The IPSP Regulation;

• Economic prudence and cost effectiveness of the IPSP;

• Pre-IPSP Projects;

• Facilitating implementation of the IPSP; and

• Implementation of IPSP Initiatives.

The OEB will not be soliciting input on the goals set out by the Supply Mix Directive since the OEB's mandate does not extend to determining whether the goals set out in the IPSP Directives are appropriate, economically prudent or cost effective. However, the OEB will consider "whether and how the IPSP achieves the goals set out in the Supply Mix Directive in an economically prudent and cost effective manner." As such the OEB will review the following issues:

• Achievement of conservation targets;

• Achievement of renewable energy targets;

• Use of nuclear energy for baseload;

• Use of natural gas is in high efficiency, high value applications;

• Replacement of coal-fired generation;

• Strengthening of the transmission system; and

• Satisfying the requirements of the IPSP Regulation.

The OEB will not be assessing the adequacy or appropriateness of the provisions of the IPSP Regulation. The OEB will determine if the requirements of the IPSP Regulation have been met. The Regulations largely fall into the following categories:

• Plan preparation;

• Alternatives to OPA procurement; and

• Environmental issues.

The Report notes that, "economic prudence requires that the IPSP be sufficiently resilient to ensure that the plan's goals, including goals for adequacy, reliability, renewable energy sources and conservation and demand management, can be achieved in the face of circumstances that turn out differently than assumed in the plan. An economically prudent plan will be able to adapt to different contingencies without causing major changes in overall costs."

The OEB recognizes that the OPA will be required to address non-quantitative, non-financial or non-economic factors while preparing the IPSP. These factors may not present a least-cost solution. Should the OPA propose a solution other than the least-cost solution, the OEB must be satisfied that the incremental benefits outweigh the incremental costs.

Initiatives that pre-date the IPSP will not be assessed as part of the IPSP review process even if these initiatives are included in the IPSP. Examples of these initiatives are the York region demand response process and the existing Standard Offer Program.

Section 1(2) of the Ontario Energy Board Act, 1998 states that the OEB "must facilitate the implementation of an approved IPSP when it exercises and performs its statutory duties." Therefore, regulatory streamlining opportunities will be sought. The Report notes that regulatory streamlining does not mean that, "applicable regulatory approvals will necessarily be avoided." These streamlining opportunities will include addressing "as many issues as feasible in relation to the proposed projects that would otherwise be reviewed on a case-by-case basis as part of another of the Board's statutory functions."

To accomplish this streamlining, issues that are adequately addressed in the context of the IPSP will not be subject to re-examination by the OEB at a later date.

The OEB notes that the OPA is expected to "work diligently towards implementation of initiatives that have been included in the approved IPSP." If there is a potential for "material deviation" from the approved IPSP, the OPA is expected to notify the OEB so that appropriate action can be taken. Therefore, the OPA is expected to monitor the implementation and effectiveness of the approved IPSP initiatives, providing the OEB, and therefore the public, with periodic reports between the triennial reviews.

The full text of the Report can be found by visiting the following site:
http://www.oeb.gov.on.ca/documents/cases/EB-2006-0207/IPSP_report_final_20061227.pdf
By Michael Morrison

OEB Issues Final Report On The Review Of The OPA'S IPSP

Ontario's Independent Electricity System Operator (IESO) has released its 18-month Outlook for the period from January 2007 to June 2008. The IESO notes that more than 1,000 MW of generating capacity is expected to be installed during the Outlook's timeframe leaving the supply-demand picture "generally positive".

Included in the new generating capacity are two natural gas fired generating facilities in the greater Toronto area. Phase one of the Goreway project, with a generating capacity of 485 MW, is expected to come into service before the summer of 2007. Phase one of the Portlands project, with a generating capacity of 250 MW, is expected to come into service before the summer of 2008. New wind generation of 200 MW is scheduled to come into service during the Outlook's timeframe. The IESO has initiated a stakeholder working group to "ensure wind continues to be successfully integrated into the power system."

The IESO notes that under a normal weather scenario, there are sufficient resources forecast within Ontario to meet requirements during the 18 months covered in the Outlook. This is true if planned generation additions come into service as expected. Under the extreme weather scenario, and if there is a delay in the in-service dates of the additional planned generation, the system could be strained and Ontario will continue to rely on imports.

The Queensway Flow project, which addresses transmission limitations between Niagara and the Hamilton-Burlington region, continues to be delayed. This project will "increase the capability of the transmission system connecting the Niagara River generation at Queenston to the grid in the Hamilton area by about 800 MW, and will permit increased imports from New York of at least 350 MW."

Forecast energy and peak demand is lower than in previous Outlooks. The IESO notes that this reduction is due to a reduction in consumption by electrically intense industries and conservation and demand response programs that have been initiated but the impact of which will be fully felt during the Outlook period. Weather-corrected energy demand is expected to be 155.1 terawatt hours in 2007. The following chart summarizes the forecast peak demand.

The full text of the Outlook can be viewed at the following site:
http://www.ieso.ca/imoweb/pubs/marketReports/18MonthOutlook_2006dec.pdf
By Michael Morrison

Market Surveillance Panel Releases Electricity Market Monitoring Report

The Market Surveillance Panel (MSP) released its 9th Electricity Market Monitoring Report, covering the period from May 2006 to October 2006, to the Ontario Energy Board (OEB). The MSP is appointed by the OEB to monitor, report on, and investigate the activities and conduct of the Independent Electricity System Operator (IESO) market participants, when appropriate.

The Report consists of standard market operations and performance data, a survey of prices, issues raised in previous reports as well as new intertie matters, the renegotiation of ancillary service contracts, demand response programs and key market indicators and the role of the real-time spot market in the 'new' hybrid market. The MSP noted in the report that there was no evidence of any gaming issues, abuses of market power or other inappropriate behaviour by the market participants or the IESO.

The average Hourly Ontario Energy Price (HOEP) was about $30/MWh lower than the same period in 2005. The MSP concluded that this was due to an increased supply in Ontario matched with more moderate weather, resulting in lower electricity demand. The Import Offer Guarantee, Congestion Management Settlement Credit, Operating Reserve and transmission losses payments, were 60% lower than in 2005. Ontario's HOEP was, on average, the lowest price among the neighbouring markets and 'net revenue' calculations based on new generation investments have continued to fall short, which was a situation similar to other markets. Over the past three years, on average, a combined cycle generator in the U.S. would have earned net revenue of $76,750/MW per year falling short of the $100,000/MW required.

Although there was a lower average demand, a new summer peak record of 27,005 MW was set during the heat wave on August 1, 2006. This underlines the trend of peak load growing more rapidly than average load, and the resulting challenges to respond to such demands. The lower HOEP also reflected the availability of additional unclear units and a outage reduction. The increased supply and lower demand resulted in a lower and less volatile HOEP, and a higher frequency of HOEP being set by coal-fired generators. This increase in inframarginal supply pushed gas and peaked hydroelectric generation made coal the marginal supplier. In this period, Ontario was a net exporter in both on and off peaks.

With the difference between the one hour pre-dispatch price and the real-time price being an important market indicator, inaccurate prices can lead to poor consumption decisions and inefficient production. This difference was lower in four of the six months in 2006 compared to 2005 and could reflect the IESO's efforts to address issues such as inter-jurisdictional transaction failures, demand forecast errors and out of market control actions. With the implementation of real-time transaction failure charges, approximately $1 million has been inputted directly to loads through settlements.

Although the province-wide HOEP consistently ignores costs such as transmission losses and congestion, zonal prices for the 10 zones within Ontario take these costs into consideration when analyzing system performance. The large differences between the zonal prices in the Northwest and Northeast in this period remained, but in southern Ontario the zonal prices were closer to each other than in previous periods and closer to the HOEP.

A key factor contributing to the convergence in zonal prices could be the increased congestion at or near the Michigan and New York interties, resulting in reduced exports from Ontario. As the congestion is not captured in the unconstrained schedule, the impact on price reductions on HOEP is not the same.

Loop flow, which is a naturally occurring phenomenon resulting from power flowing on parallel paths, appears across the interties and transmission interfaces within Ontario. It reduces available transmission for intertie scheduling and efficient dispatching of Ontario generation. The increase in loop flow in the last year is presumed to be the major cause of the higher level of constrained off exports. Increased loop flow can result in losing efficient trade opportunities and reduce import capability during the shortage conditions. If Hydro One and the IESO were to finalize an agreement with the Midwest Independent System Operator and the International Transmission Company, the total loop flow will be reduced substantially and a large portion of the observed loop flow could be controlled.

In the months of January to August 2006, the IESO applied a higher scheduling limit on its interface with New York than the New York Independent System Operator as the IESO did not know that New York had lowered its scheduling limit. This resulted in export transaction failures and adversely affected market performance. The MSP suggested that a joint review by the two operators be carried out and that the IESO consider proper treatment of share activation operating reserve and loss of transmission elements. Additionally, the Report advises that all forms of incremental supply be treated in a manner that accurately reflects the scarcity conditions in the market at any given time.

In the six demand response programs reviewed in the Report, only the IESO 5-minute Dispatchable Load program did not have any shortcomings. The main problem is a failure to recognize that incentive programs can induce customers to curtail consumption at times when the value they derive from the service is greater than the incremental cost of providing it. This is not conservation in its true sense. Additionally, to avoid over scheduling of imports and generation, these programs need to be integrated into the wholesale market's dispatch decision process and allow price-responsive loads.

The MSP's oversight activities focus on the investment, consumption and dispatch efficiency of IESO-administered markets. Dispatch decisions in the new hybrid market must be continually made in the spot market, but such decisions affecting consumption and investment efficiency have been largely subsumed by the government's policy initiatives. The spot market should play a central role to ensure that all such decisions are efficient and both a hybrid and spot market design should be encouraged to allow accurate reflections of supply and demand conditions. The MSP further believes that any changes in spot market design would increase the quality of signals for planners, regulators, producers and consumers. Lastly, the MSP believes that, to the extent the cost of OPA contracts and demand management decisions can be reflected through real-time prices as opposed to being reflected in non-market uplift cost to consumers, the efficiency of the hybrid market would also be served.

The Report, which is meant to serve as a detailed source on market operations for the specific period, concluded that the market continued to perform well during the period between May 2006 and October 2006 but noted that there were substantial decreases in prices when compared to the same period in 2005.

For more information and the full report, please visit:
http://www.oeb.gov.on.ca/html/en/industryrelations/msp_reports.htm

British Columbia Transmission Corporation (BCTC) has announced that it expects investments of $3.2 billion in B.C.'s transmission assets over the next ten years. BCTC feels that this investment is required to operate and expand the 18,000 kilometer electricity grid around the province. Its innovation program will focus on three main areas that will increase the power transfer capability of existing assets, extend the life of assets and improve system reliability and security.

This BCTC plan, F2007/08 - F20/16/17 Capital Plan, outlines the capital investments for the next two years, and provides an outlook of potential investments through to 2017. The plan focuses on ensuring that there is adequate transmission capacity to meet customer requirements while maintaining reliability and performance levels.

The $3.2 billion figure can be divided into three main expenditures - $1.9 billion on growth related expenditures, $1.1 billion on sustaining expenditures and $0.17 billion on computer and control centre expenditures. This figure is $700 million more than the fiscal 2006 ten-year Capital Plan and can be attributed to increased demand for electricity and aging infrastructure.

Approximately $0.6 billion is concentrated in two major projects - the Vancouver Island Transmission Reinforcement Project (to be in service by 2008) and the Interior to Lower Mainland Transmission Reinforcement Project (to be in service by 2014).

Other major area transmission system reinforcements include $51 million in Central Vancouver Island, $52 million in the Golden 69kV system, $50 million in the North Thompson 138 kV system and $215 million on Lower Mainland Transmission projects.

BCTC aims to identify innovative solutions to apply new technologies for extending the existing life of transmissions assets and maximize available capacity. In addition, the System Control Centre and four Area Control Centres will be updated with a modern energy management system located at a new control centre and backup site. BCTC is also proposing to replace existing mechanical temperature monitors on station performers, implement Real Time Rating which would allow the BCTC Control Centre to operate two 500 kV submarine cable circuits at maximum capacity and extend the life of over 22,000 steel lattice towers by about 25 years.

For more information, please visit: http://www.bctc.com
By Nichole Chen

European Commission Announces New Energy Policy

The European Union (EU) has enacted legislation that gives natural gas and electricity consumers the ability to shop freely for their energy supply (Gas directive 2003/55/EC, Regulation 1775/2005 and Electricity directive 2003/54/EC and Regulation 1228/2003). Consumers are to have this ability from July 2007, at the latest. For more information on this issue please refer to the April 27, 2006 issue of energy@gowlings. As the July 2007 deadline approaches, the European Commission (EC) revealed a new energy policy to help its constituents face the challenges of the 21st century.

The main challenge facing the energy community in Europe, and globally, is securing competitive and clean energy against global conditions of climate change, increasing demand and possible future supply uncertainties. The EC notes that if one EU member state fails to meet this challenge then all EU member states will be affected.

The objectives of the new policy are: combating climate change, promoting growth and limiting the EU's external vulnerability to gas and oil imports. The core objective of the policy will be reducing greenhouse gas emissions from energy consumption by 20% by 2020. Meeting this objective will allow the EU to meet the challenges of sustainability, competitiveness and security of supply. The EC notes that, in light of the many submissions to its paper titled A European Strategy for Sustainable, Competitive and Secure Energy, the target should be increased to a 30% reduction by 2020 and 60-80% reduction by 2050.

The renaissance of the industrial revolution is upon us, a time when industry must compete with higher energy efficiency and lower carbon dioxide emissions. Recognizing that each element of the policy must work in concert if the objectives are to be realized, the EC will focus on the following issues:

• Improving energy efficiency;

• Raising the share of renewable energy in the energy mix;

• Introducing measures to ensure that the benefits of the internal energy market reach everyone; and

• Reinforcing solidarity among EU member states with a more long term vision for energy technology development, a renewed focus on nuclear safety and security and determined efforts for the EU to "speak with one voice" with international partners including energy producers, energy importers and developing countries.

The EC believes that the first step in driving this policy forward is for the European Council and Parliament to:

• Endorse an EU objective in international negotiations of a 30% reduction in greenhouse gas emissions by developed countries by 2020;

• Endorse the EU commitment to achieve, in any event, at least a 20% reduction in greenhouse gases by 2020;

• Confirm that additional measures are necessary to make the potential benefits of the internal electricity and gas markets a reality for all EU citizens and businesses. This will include a commitment to further unbundling, effective regulation through the harmonization of power, harmonization of technical standards, establishing a new community mechanism for transmission system operators responsible for co-ordinated network planning, reporting to national regulators and the EC and endorsement of minimum standards regarding transparency;

• Endorse the need to make further progress in ensuring the solidarity between member states in the event of an energy crisis or a disruption in supplies;

• Endorse the binding targets of 20% for the share of renewable energy in overall EU energy consumption by 2020 and 10% minimum Biofuels;

• Confirm the priority of making rapid progress in providing a clear perspective when coal and gas-fired plants will need to install CO2 capture and storage;

• Confirm the importance of "speaking with one voice" on international energy issues; and

• Welcome the UC's intention to put forward a new Strategic Energy Review every two years.

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