Canada: Energy @ Gowlings – October 2006

Edited by Paul Harricks

• Gowlings Sponsors and Moderates APPrO Conference

• Canada's Energy Outlook From Natural Resources Canada

• Ontario's IESO Releases 18-Month Outlook

• California Sues Carmakers and What It Means For Canada

• Nova Scotia Increases Commitment to Renewable Energy

• Estimates of Maximum Underground Working Gas Storage Capacity in the U.S.

Gowlings is pleased to announce that it will again be a major sponsor for the annual Association of Power Producers of Ontario (APPrO) conference. The conference is being held in Toronto on November 14^th and 15^th. Tom Brett, Gowlings senior partner and co-chair of the Toronto Energy and Infrastructure Industry Group, will moderate the session titled Navigating NIMBY & Approval Gridlock.

The theme for the 2006 conference is Critical Connections and will address the following issues:

• What should be going on while the sector waits for the final approved Integrated Power System Plan (IPSP)?;

• What kind of transmission policy decisions should be reflected in the final IPSP?;

• Where is the Natural Gas Forum taking us? Is the risk reasonably allocated? What does it mean for developers and operators?;

• Introduction of the Standard Offer Program;

• Options for new and revised Ontario Power Authority procurement mechanisms;

• The Independent Electricity System Operators visions for the future of the sector;

• What's needed to attract more new supply;

• Navigating NIMBY & approval gridlock;

• The implications of Ontario's nuclear reconstruction for transmission system development and grid operation; and

• What's working and what's not with the province's procurement of green power.

Further information about the conference can be found by visiting the following site:
http://conference.appro.org/

Natural Resources Canada (NRCan) has produced a report titled Canada's Energy Outlook: The Reference Case 2006. This report provides a new outlook for Canada's energy supply and demand to 2020 and:

• Identifies pressure points and emerging issues in Canadian energy markets;

• Contributes to an informed public discussion on energy and related economic and environmental issues in Canada; and

• Provides a reference scenario from which new energy and climate change policies can be consistently evaluated.

The previous report was issued in 1999, modified in 2002, and since then there have been substantial changes to the major influences on energy projections. NRCan also notes that, since the last outlook was issued, there have been some major changes in federal, provincial and territorial energy and environmental policies and programs. Changes from the 1999 report include:

• Crude oil prices are assumed to be about double;

• Natural gas prices are expected to be about three times higher;

• The economy is expected to be eight per cent larger in 2010;

• Oil sands production is expected to be significantly higher; and

• The Mackenzie Delta gas pipeline is expected to be in service in 2011.

The principal assumptions used in the outlook are:

• Population growth will be about 0.7 per cent annually and Real Gross Domestic Product will increase at an annual rate of about 2.4 per cent to 2020;

• Crude oil prices will decline to US$45 (2003 dollars) per barrel by 2010 and will remain constant thereafter. Although lower than today's high level, this is much higher than the oil prices prevailing through most of the last two decades; and

• All but two of Canada's nuclear power plants will stay in service for at least eight more years, or will be refurbished and returned to service. The two units at Pickering A, which are currently out of service, will remain so indefinitely.

NRCan is projecting that total energy demand will grow by 1.3 per cent per year. Residential energy demand is projected to increase by about 1 per cent per year, commercial energy demand is projected to increase by about 2.4 per cent per year and industrial energy demand is projected to increase by about 1.1 per cent per year.

NRCan believes that conventional oil production will decline during the time frame of the outlook. However, production from the oil sands is expected to rise significantly to 2.9 million barrels per day. This level of production will represent about 80 per cent of total crude oil production in 2020, more then offsetting the decline in conventional crude oil production.

Natural gas production is expected to peak in 2011 at 6.6 trillion cubic feet (TCF) and then decline. The decline in natural gas production will be somewhat offset by the development of the Mackenzie Delta and by coalbed methane production. By 2020, net exports of natural gas will decline to 1.3 TCF. Currently, net exports are in the 3.7 TCF range.

The projected increase in energy demand and a changing energy production mix will lead to growth of greenhouse gas (GHG) emissions from 758 megatonnes (MT) in 2004 to 828 MT in 2010 and 897 MT in 2020. The 2010 level is 265MT above Canada's Kyoto target.

The full report can be viewed by visiting the following site:
http://www.nrcan.gc.ca/inter/pdf/outlook2006_e.pdf

Ontario's Independent Electricity System Operator (IESO) has released its 18-month Outlook for the period from October 2006 to March 2008. The Outlook notes that Ontario set a new peak record of 27,005 megawatts (MW) for peak demand on August 1, 2006. The province's ability to withstand this new peak came as a result of excellent performance from Ontario's generators, transmission upgrades and new market mechanisms. Under normal weather conditions, there are sufficient resources available to meet Ontario's needs during the forecast period. However, under an extreme weather scenario, the system will be strained and additional supplies from outside of Ontario would be required.

During the 2006 Labour Day weekend demand was only 12,000 MW. This, coupled with record low spot prices, high levels of baseload generation, below normal temperatures and a reduction in export capability due to a forced intertie circuit outage, meant that the Hourly Ontario Energy Price (HOEP) was ($3.10)/MW hour. This is the first time that the HOEP has been negative since market opening. During that hour, consumers that pay the market price received a credit.

Completion of the Goreway Station Phase One will help meet the expected increase in Ontario demand during the summer of 2007. This station will add 485 MW of generation to the grid. Work also continues on the Toronto Portlands Energy Centre. It is anticipated that 330 MW will be in service by the summer of 2008. The wind sector currently has 300 MW of installed capacity with another 366 MW of installed capacity scheduled to come into service during the Outlooks time frame.

The IESO notes that, due to unforeseen circumstances, the transmission system expansion in the Niagara region continues to be delayed. This delay affects the use of available Ontario generation and imports into the province.

Demand continues to be similar to previous Outlooks. A reduction in energy-intensive load has led to a reduced energy demand throughout the forecast period. Weather-corrected energy demand is expected to be 154.4 terawatt hours (TWh) for 2006, increasing to 156.7 TWh in 2007. The following chart summarizes the forecast peak demand.

California Sues Carmakers and What It Means For Canada

On September 20, 2006, the State Attorney of California, Bill Lockyer, filed a lawsuit against six leading U.S. and Japanese auto manufacturers, alleging that greenhouse gases from their vehicles have caused billions of dollars in damages. This lawsuit is the first of its kind which seeks to hold manufacturers liable for the damages caused to the environment by their vehicles' emissions. More information about California's move to cleaner air and curbing global warming can be found in the September 20,2006 issue of Energy @ Gowlings .

The defendants in this suit are Chrysler, General Motors, Ford, Toyota, Honda and Nissan. The complaint alleges that, under federal and state common law, these automakers have created a public nuisance by producing vehicles that collectively emit massive quantities of carbon dioxide. As such, the state has had to spend millions of dollars on planning, monitoring and initializing infrastructure changes to address this large spectrum of current and anticipated impacts.

Environmentalists hail this lawsuit as another weapon for the state to seek reduction in greenhouse gas emissions and spur the auto industry to build less environmentally-degrading vehicles. A similar nuisance suit had previously been brought by other attorneys-general against utilities before a federal court in New York but it was dismissed.

Canada's response saw the Environment Minister summoning Canada's big car manufacturers to a meeting to lay out plans for Canada's first attempt at regulating car emissions. This marks the first time carmakers will face regulations in Canada. Currently, Canada maintains the choice between a written voluntary agreement to meet emission goals or an understanding that carmakers would follow US standards. The aim is to have Canada fall inline with North American-wide standards by 2010, which would most likely involve adopting California's clean air regulations.

Other states in the U.S. are awaiting the court decision in California's lawsuit to adopt California's new high bar, but Canada is not expected to delay its initiative much longer.

Nova Scotia Increases Commitment to Renewable Energy

The government of Nova Scotia is planning to increase its electricity generation from renewable sources by at least 20 per cent by 2013. Nova Scotia's renewable supply mix includes wind, tidal, solar, hydro and biomass.

"Our government is making a commitment to renewable energy in Nova Scotia" said Energy Minister, the Honourable Bill Dooks. "We will increase our renewable energy, but we will do it in a way that is achievable and that protects consumers and businesses from large increases in the price of electricity." During a speech at the Green Energy Conference in Halifax, Dooks also promised that renewable energy producers would be able to sell directly to municipal utilities by February 2007.

Dooks also noted the following steps that the Nova Scotia government is taking to enhance renewable energy:

• A rebate on solar water heating panels for residential and commercial sectors;

• $20 million commitment to get Halifax hospitals and universities off Bunker C fuel oil and on to cleaner natural gas;

• Installing, at no cost, 9,000 energy–efficient thermostats in the homes of low-income Nova Scotians;

• Funding a green-roof project at the new Citadel High School;

• Funding Nova Scotia's Climate Change Centre;

• Creating Conserve Nova Scotia; and

• Enhancing the tax structure by enacting the energy efficiency tax credit.

Across the lower-48 states, natural gas is commonly held in inventory in either depleted reservoirs in oil and/or natural gas fields, aquifers or salt cavern formations. The working gas storage as of September 8, 2006 was 3,084 billion cubic feet (Bcf), which widely exceeded comparable points in history. As such, the potential maximum volume of natural gas that may be simultaneously held by storage operators has been of growing interest.

The following discussion will identify various types of companies involved in storage operations, focus on the concept of maximum capacity and present estimates of maximum working gas volumes.

There are four principal types of owners/operators of underground storage facilities, namely:

• Interstate pipeline companies;

• Intrastate pipeline companies;

• Local distribution companies (LDCs); and

• Independent storage service providers.

There are 123 entities currently operating approximately 400 active underground storage facilities in the U.S., with most of the working gas being held in storage facilities for shippers, LDCs or end users who own the natural gas and hold rights to the storage capacity. The type of entity that owns/operates the facility will determine how the facility's storage capacity is to be used.

Interstate and intrastate pipeline companies rely extensively on underground storage to balance load and manage system supply on their long-haul transmission lines. LDCs, on the other hand, generally use underground storage to serve customer needs directly and store natural gas to shift supplies from the injection season (April – October) to the winter heating season (November – March). Lastly, salt formations and other high deliverability sites which are owned by independent storage service providers are used almost exclusively to serve third-party customers such as marketers and electricity generators.

There are various aspects of capacity measurement and industry operations which preclude the ability for a single, definitive estimate to be made of maximum capacity. Given that the capacity estimates have been made for individual facilities, one form of estimating aggregate storage capacity is the sum of design capacity for all facilities. However, there are various reasons why this is a poor estimate for practical purposes.

When the industry reaches its collective maximum, some portion of capacity may not be fully used. This under-utilization may be explained by a variety of factors including:

• Inefficient mainline and LDC pipelines requiring spare storage capacity;

• Levels of working gas in some fields may depend on commercial arbitrage opportunities available at any point to the individual owners;

• Shippers holding capacity rights may elect to withhold a portion of reserve capacity;

• Some storage facilities may be undergoing maintenance or operational upgrades; and

• New storage fields may not be fully operational due to prevailing high prices leading to delayed investments by operators in base gas.

Aside from these, there are other factors that could result in a difficult estimation of actual storage volumes such as regional market conditions altering storage decisions and ultimate performance of the industry as a whole.

There are alternative approaches that can be used to estimate the volume of natural gas being held simultaneously, all of which are focused on estimates of working gas capacity as the most relevant estimate.

Working Gas Design Capacity – With a storage facility holding only working and base gas, an estimate of aggregate working gas capacity can be obtained by subtracting the sum of base gas volumes from the sum of total design capacity for all fields. However, the issue with this engineering-based method of estimation is that the result exceeds any other reliable estimate of aggregate capacity that industry would ever fill with working gas.. This estimate would need to be adjusted to account for situations where realized volumes in storage might be kept below the maximum engineering-based total.

Effective Working Gas Capacity – By reducing the working gas design capacity using a recognized industry 'rule-of-thumb', estimations of maximum working gas capacity can be made. According to recent studies, the industry would operate with at least a 5 per cent cushion of unused storage capacity as of October 31. Assuming a 5 per cent cushion for all operators, maximum effective working gas capacity for all fields as of the end of June 2006 would be estimated at 3,829 Bcf, a level which exceeds the largest recorded volume by more than 10 per cent and as such, there lies the need for other limiting factors to re-evaluate this estimation.

Non-Coincident Peak Working Gas Volume – The last option is to sum the peak volumes for any reported storage fields in a recent historical period. However, the problem with this method is that the non-coincident peak volume overstates the amount of actual storage achieved at a given point in a selected period because it would not account for difference in timing of occurrence. Each storage field might not have achieved its practical maximum which would suggest the estimation to yield a more conservative result.

It should be noted that these methods of estimation are based on facilities that are used normally with regular injections and withdrawals.

The 'hard' threshold for maximum storage capacity is the sum of engineering design capacity for all facilities but is seen to be irrelevant from a practical standpoint because the industry is unlikely to approach this level. The use of a industry standard to adjust total design capacity is difficult because of the lack of agreement on the capacity factor to be used. The non-coincident peak volume provides a more conservative estimate but is flawed as some facilities used in the estimation may not have been at their practical maxima. Therefore, any estimations of maximum storage capacity should be juxtaposed with these various limitations.

Additional information can be found at: http://www.eia.doe.gov

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.