Publications

Oil Spills and First Nations: Exploring Environmental and Land Issues Surrounding the Northern Gateway Pipeline
February 2012

The Enbridge Northern Gateway pipeline project offers a classic example of the controversy that increasingly attaches itself to energy infrastructure projects: how to balance economic development with environmental conservation. Consequently, discussions surrounding the development of Northern Gateway have become controversial. Many stakeholders claim the economics overwhelmingly favour pipeline construction, while others favour a risk-averse approach towards anything that may potentially contaminate a pristine area. To further complicate matters, British Columbia First Nations land claims are not well established, and it is these lands which the pipeline would traverse; these are the areas that would be damaged if an oil spill were to happen. This report addresses many of the environmental issues, providing insight into Enbridge’s Environmental Impact Assessment; it also explores the recent history of aboriginal land claims and the degree to which First Nations retain traditional land rights in contemporary Canadian society.

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Printed copies of this report are available through CERI at a cost of $50.00 per copy plus shipping/handling. Please send us an email at This e-mail address is being protected from spambots. You need JavaScript enabled to view it with the name of the report, the number of copies and the shipping address. Your order will be processed as soon as possible. Thank you.

Pacific Access: Overview of Transportation Options
January 2012

While not a recent concept, oil tankers mooring off British Columbia’s west coast have caused quite a stir. In fact, oil tankers have been loading crude off the west coast since the 1,150 kilometre Trans Mountain Pipeline (TMX) opened in 1957. Thus far, Kinder Morgan’s Westridge Terminal remains the only oil terminal on Canada’s west coast.

This, however, may change.

There are currently 3 pipeline proposals and a rail proposal to transport crude oil from Alberta’s oil sands to the west coast. All aforementioned proposals require marine terminals to be built to transport crude oil to energy-hungry Asian markets. As such, these proposals are drawing a lot of attention—from industry, environmental groups, First Nations and various governments.

This study provides an overview of transportation options, as well as explores and investigates oil tanker and marine terminal safety. In addition to providing a background of oil tankers and the international regulatory structure that governs the safety of the shipping industry, various operational and design measures are also discussed. These mandatory measures are discussed from a Canadian perspective, exploring regulations on a national and provincial level, bringing it down to the terminal level. The latter focuses on Port Metro Vancouver (PMV)—Canada’s busiest port and only marine terminal on the west coast to export crude oil—and Enbridge’s proposed Northern Gateway Marine Terminal. Their unique facilities, marine environments and regulations and safety protocols governing the movement of oil tankers are examined, respectively.

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Overview of Eastern and Atlantic Canada's Petroleum Industry
and Economic Impacts of Offshore Atlantic Projects (2010 - 2035)

CERI Study 127
November 2011

There has been a recent renewed interest in onshore hydrocarbon development in the provinces of Quebec, Ontario, New Brunswick, Prince Edward Island, Nova Scotia, and Newfoundland and Labrador due to the region's significant potential. However, a host of issues including regulatory initiatives, public opposition, a lack of large scale commercial projects, and the infancy of the petroleum industry in this region, makes it difficult to establish an outlook for potential development over the long term. Meanwhile, offshore projects in Nova Scotia and Newfoundland and Labrador have become the most relevant developments outside the Western Canada Sedimentary Basin (WCSB) over the last couple of decades and are expected to continue to be the focus of the industry over the coming decades.

This report presents an overview of the petroleum industry in Eastern and Atlantic Canada, while it also presents CERI's outlook for production and investment associated with offshore projects in Nova Scotia and Newfoundland and Labrador over the 2010 to 2035 time period. Finally, this report presents the economic impacts across Canada and the United States associated with continued operations and new developments offshore Atlantic Canada including value added gross domestic product, employment and employment compensation impacts, as well as taxation and royalty revenues.

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Emission Abatement Potential for the Alberta Oil Sands Industry and Carbon Capture
and Storage (CCS) Applicability to Coal-Fired Electricity Generation and Oil Sands

CERI Study 126
October 2011

In an increasingly greenhouse gas (GHG) conscious environment, Alberta has faced criticism for its heavy emissions within the oil sands industry and its utilization of coal-fired generation. Oil sands development is an expanding industry with production expected to approximately triple in the coming decades; consequently, emissions will rise markedly and if left unhindered, the oil sands will be a significant emitter of GHGs in the future. Simultaneously, the higher emissions from coal power generation compared to other forms of electricity generation have incited a largely uncertain future for coal generation. Furthermore, the advent of a carbon tax in Alberta and Canada’s commitment to the Copenhagen Accord, have endorsed the proliferation of lower GHG intensity technologies. Consequently, under the aforementioned pressures, various stakeholders have hastened to devise schemes and promote technologies that reduce emissions in order to avoid significant future costs (both social and financial) that could hinder development. This has resulted in a myriad of technologies which range from improvements in efficiency, to deep-cuts in emissions through sequestration.

CERI has evaluated these emerging technologies to determine applicability, and has attempted to provide context over the advantages and disadvantages of implementing such technologies. Furthermore, a projection of a business-as-usual scenario and emission factors for different technologies were developed in order to determine the potential abatement of emerging technologies. CCS was also examined in detail as a front runner for a potential renaissance of “clean-coal” technologies and applicability within the oil sands.

This study is primarily geared towards readers seeking to understand the sources of GHG emissions in the oil sands industry and the role of emerging technologies. It is also intended to update the reader on the state of CCS, the requirements for implementation, and potential barriers.

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Economic Impacts of Drilling, Completing and Operation of Gas Wells in Western Canada (2010 - 2035)

The exploration and development of natural gas resources within the Western Canada Sedimentary Basin (WCSB) peaked in 2006 with the completion of over 23,000 new wells, a production level of 17,500 mmcf/day and royalties paid to Alberta, British Columbia and Saskatchewan totalling $8.2 billion. This included conventional resources; coalbed methane (CBM) and early developments of shale/tight gas resources (BC Montney area). The worldwide recession of 2008 affected the gas industry in the same fashion as other industries around the world. Demand for gas retracted, gas prices fell and new drilling activity slowed. Between 2007 and 2010, new drilling activity within the WCSB dropped by close to 70 percent. Production started to decline as new wells failed to counter the natural decline from existing wells. In concert with the production decline, prices dropped resulting in provincial royalties of just $2 billion. At the same time, shale gas developments in the US ramped up to the point where gas supply was starting a push back of Canadian imports into the US. The golden age of gas within the WCSB was in trouble and the future is unclear! This report presents a “realistic” development forecast for the WCSB gas industry in the form of drilling activity, both vertical and horizontal wells, production levels and royalty payments. In addition, the capital requirements for development and operation of existing and future wells are calculated and the economic impacts for Canada and the United States are estimated.

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A Decade of Staged Oil Sands Growth (2010 - 2020)

CERI Study 125, Extension A

Canadian Oil production, which includes conventional oil, diluents, bitumen and synthetic crude oil (SCO), from the Western Canada Sedimentary Basin (WCSB), is estimated to exceed 2.9 million barrels per day (bpd) by the end of 2011. In addition after accounting for a resurgence of conventional oil developments and the completion of construction for 3 new oil sands projects, the production capacity out of the WCSB will approach 3.1 million bpd by the middle of 2012 and is forecasted to continue to grow crossing the 3.5 million bpd by 2013. At that point in time production will have exceeded the operational capacity of the export pipeline system leaving the WCSB either west to the port of Vancouver or east/ southeast to the Ontario and US PADD 2 markets? The next tranche of oil sands projects requires additional export capacity either in the form of new pipelines (Keystone XL , Gateway or Kinder Morgan Trans Mountain Northern Leg) or increased rail transport (CN Pipeline on Rail). This study examines the economic impacts of developing these oil sands projects which have been approved by the regulator and are awaiting increased export capacity to access the market. These impacts include the construction and operation of oil sands projects alone and does not include the impacts associated with the construction or operation of the pipelines or rail systems.

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Economic Impacts of Drilling, Completing and Operating Conventional Oil Wells in Western Canada (2010-2035)

June 2011

Conventional oil production from the Western Canada Sedimentary Basin (WCSB) has been declining since the early 1970s after reaching a peak of approximately 2 million barrels per day. In 2010 production from the basin had declined to 0.9 million barrels per day and it appeared that the decline would continue unabated. 2010 can now be viewed as a restart year for the conventional oil industry not just based on the resurgence in the number of wells drilled, driven by oil price, but more importantly based on the number of horizontal wells drilled driven by the success stories in shale gas developments. The industry is returning to old, thought to be depleted, reservoirs equipped with horizontal well drilling techniques to recover more of the resource that remains in the ground. The number of horizontal wells grew from 24 percent of oil wells drilled in 2006 to 62 percent of oil direct wells in 2011 and the future looks like the trend will continue. This report examines the growth potential in drilling activity, the effect of change towards horizontal drilling, and the increased production potential from conventional oil within the WCSB. In addition, the capital requirements for development and operation coupled with the economic impacts both for Canada and the United States are estimated.

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To download the map for Alberta referenced in Appendix A, click here.

To download the map for Saskatchewan referenced in Appendix A, click here.

Economic Impacts of Staged Development of Oil Sands Projects in Alberta (2010-2035)

CERI Study 125

The Alberta oil sands industry is once again expanding with a number of major projects under development and still more proposed for the future, reflecting a considerable growth that was deferred during 2008-2009 recession. New pipelines will be needed to ship bitumen crude to destinations in the United States and/or Canada’s west coast to reach Pacific Rim markets. This report looks at export pipeline proposals, namely TransCanada’s Keystone XL, Enbridge’s Northern Gateway and Kinder Morgan’s Trans Mountain expansion and evaluates the economic impacts of staged development of Alberta’s oil sands projects according to the proposed in-service dates of these pipelines. The report shows that without additional pipeline capacity, the benefits that will be lost in Alberta, Canada and the US are substantial.

This study captures the direct, indirect and induced effects of oil sands infrastructure investments and ongoing operational expenditures in four different scenarios. Using Input/Output economic modeling techniques, the report details the economic impacts in terms of gross domestic product (GDP), employment, employee compensation and government tax revenues.

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Economic Impacts of New Oil Sands Projects in Alberta (2010-2035)

CERI Study 124

Energy is at the core of the US-Canadian bilateral relationship. There is no more secure supplier of oil to the United States than its northern neighbour, and continuation of this secure supply depends in large part on the further development of oil sands projects.

This study focuses directly on the economic impacts of the Alberta oil sands between 2010 and 2035. Using Input-Output (I/O) economic modeling, the report quantifies the economic impacts of the oil sands on GDP, employment, employee compensation, and government revenues. The model incorporates the economic interrelationships between the Canadian federal, US federal, Canadian provincial, and US state economies. Therefore, it is able to capture the direct, indirect, and induced effects of oil sands infrastructure investments and ongoing operational expenditures on all of the above-mentioned economies.

CERI is noted for its expertise in I/O modeling, having completed numerous major studies for government and industry. This study represents yet another advance: the I/O tables have been updated, the trade-flow matrix between provinces and the US has been calibrated to allow for more accurate mapping of trade relations, and the model formulation and approach have been enhanced to capture with increased precision the relations among various sectors and local economies of different regions.

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North American Natural Gas Market Dynamics: Natural Gas Vehicles – A Review

CERI Study 123 - Section IV

This paper explores the possibilities of introducing natural gas vehicles (NGVs) to the North American Transportation sector. Noting that NGV’s have much to offer in terms of reduced greenhouse emissions, increased efficiencies and, in many cases, lower operating costs, the paper nevertheless argues that the place for NGVs in the overall transportation mix will be a small one for years to come. Grandiose visions of an NGV revolution, such as the Pickens Plan, are found to be infeasible over the next decade. Instead, the idea of introducing NGV’s into certain transportation corridors, as recommended by NRCan in their report “Natural Gas Use in the Transportation Sector”, is considered both possible and desireable. However, it will require time, effort, education, incentives, and infrastructure development to establish natural gas as a true alternative to crude-based fuels.

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North American Natural Gas Dynamics: Coal-fired Generation in North America

CERI Study 123 - Section III

Coal power plants conjure up strong images for individuals and groups on both sides of a raging debate about the future of electricity generation and the environment.

Whether they are changes in national legislation and regulation, or state/provincial programs and initiatives promoting reductions in GHGs or increasing the use of various renewables, many jurisdictions are trying to discover the balance between minimizing environmental impacts and maintaining a modern, reliable electricity system. While the province of Ontario is moving steadily to permanently shut down all coal-fired generation by 2014 – as part of the Open Ontario Plan – other jurisdictions suggest that advances in coal technology, such as supercritical coal-fired generation, CO₂/O₂combustion, CO₂ capture and sequestration and Integrated Gasification Combined Cycle (IGCC) offer cleaner coal options.

Amidst the debate and discussions and planning, one thing is abundantly clear; the worlds’ thirst for energy is growing, as is the demand for energy in North America.

This study focuses on North America and the current state of coal-fired generation in the United States and Canada, within a global context. The latter reviews global coal reserves, production and consumption. While not providing a synopsis of who is pulling and pushing in the debate to find a balance over energy production and the environment, this study reviews the current state of coal-fired power generation in North America and explores various elements and statistics of the industry in the US and Canada.

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North American Natural Gas Market Dynamics: Global LNG – A Review

CERI Study 123 - Section II

The global liquefied natural gas (LNG) market has grown significantly over the past decade, with new emerging LNG markets and a growing number of LNG producers. A plethora of new LNG re-gasification and liquefaction projects that are currently under construction will commence operations over the next few years, and construction will begin on many of the proposed LNG projects that are now in the planning phase. According to International Energy Agency (IEA) estimates, annual LNG trade will more than double from 2008 levels to approximately 17.7 TCF, or 48.4 BCFPD, by 2035.

The purpose of this study is to present an overview of existing LNG re-gasification and natural gas liquefaction capabilities around the world and to provide projections of future capacity additions at the regional and global levels. LNG re-gasification and liquefaction capacities in each region are summed by status and by start-up year, and probability factors for cancelling or delaying capacities, based on the status, are applied to produce a projection of future capacities. These probabilities will be adjusted depending on the region, as the likelihood of projects proceeding, or being delayed, will be affected by region-specific factors. The global LNG overview will also provide a brief discussion on existing LNG contracts and potential global LNG spot market supplies.

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North American Natural Gas Dynamics: Shale Gas Plays in North America – A Review

CERI Study 123

If the recent boom is any indication, the future potential of shale gas is nothing short of dramatic.

Given the sheer magnitude of the resource potential of shale gas, it essential to understand shale gas and its potential role in an environment of declines in conventional gas production in both Canada and the US. For the investor, it is important to understand the various players and the various shale gas plays. And for anyone involved in the energy industry—or interested about energy—it is prudent to be aware of this unconventional source of natural gas that is representing an increasingly large and growing share of the recoverable resource base

This purpose of this study is to review shale gas plays in North America, their geological differences, the players involved and future potential of various basins. This study explores the questions of where, who and when versus the what, how and why. Many people are familiar with several, if not all, of the big five shale plays in North America–the Barnett, Fayetteville, Haynesville, Marcellus and Woodford Shales. However, while these plays are basking in the media, there are many other plays that are far less known—that may end up being more productive than the aforementioned. Exploring other less well-known but potentially prolific shale gas plays in North America, this study will also discuss briefly regulatory and environmental issues regarding the development of shale gas.

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Canadian Oil Sands Supply Costs and Development Projects (2010-2044)

CERI Study 122

The oil sands development exhibited moderate growth in 2010 relative to prior years, reflecting the resumption of the many oil sands projects that were deferred during the 2008-2009 economic recession. The world’s major economies are starting to rebound (oil demand is increasing), credit is becoming available to oil sands proponents, and mergers and acquisitions are ramping up. The future outlook for potential export markets for bitumen could be expanded beyond the US borders. New oil sands technologies are emerging in pilot stages that promise to reduce the environmental impact while maintaining economic growth and the creation of high value employment.

This is the Canadian Energy Research Institute’s (CERI) sixth annual oil sands industry update, examining production, supply costs, and constraining factors for oil sands development. CERI monitors and reviews all the oil sands projects (used in the unconstrained case), and also develops a more realistic assessment—the CERI Realistic Scenario—based on likely timing conflicts, contingencies, and project delays and deferrals. From the Realistic Scenario stem the projections of production, investment, natural gas requirements and GHG emissions, as well as supply costs for SAGD, surface mining recovery, and bitumen upgrading.

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The Contributions of the Canadian Oil and Gas Service Sector to the Canadian National Economy

Prepared for the Petroleum Services Association of Canada

October 2010

The oil and gas component of the Canadian economy is historically focused on hydrocarbon production, pricing, royalties and taxation. Success or failure is usually measured by levels of production, the profitability of hydrocarbon exploration and production companies (E&P), and royalty and taxation levels of various levels of government. Often absent from this debate is the myriad of companies and tens of thousands of workers that support the efforts of the E&P sector, the oil and gas service sector (OGS). Products and services employed in direct support of the E&P activities include exploration, drilling, completion, production, construction, processing, transportation, logistics, manufacturing, maintenance and fabrication.

The purpose of this report is to detail the results of CERI’s challenge to determine the true contribution of the OGS sector to the Canadian economy through economic metrics of GDP, employment and taxation.

The report is available for download.

Canadian Oil Sands Supply Costs and Development Projects (2009 - 2043)

Study 121

November 2009

This year will mark the release of the Canadian Energy Research Institute’s (CERI’s) fifth annual oil sands industry update, examining production, supply costs, and constraining factors for oil sands development. The past year can be characterized as uncertain, and a “blood bath” for the global oil and gas industry. Fortunately, the dire predictions of a recession that is “worse than the Great Depression” have proven to be off the mark, as the North America economy is showing signs of an economic recovery. The recovery is already raising hopes that oil demand will once again surge and prices will follow.

While announcements have been made by Imperial Oil that they are staying course and proceeding with the Kearl oil sands projects, other major producers such as Royal Dutch Shell and Total have raised concerns that current oil prices are insufficient to justify new oil sands projects. The critical word is current. As the developed world moves forwards with its economic recovery and the BRIC nations (Brazil, Russia, India, and China) return to high levels of growth, it does not take much of an imagination to see oil prices (WTI) pushing north of US$80 to US$90 per barrel. This CERI Report provides an up-to-date assessment of oil sand production and supply costs, and will answer the question of “what is the trigger price that will bring Alberta back to a period of oil sands expansion?” Our previous edition was a best seller; the 2009 updated version will be available November 3, 2009.

CERI monitors and reviews all the announced oil sands projects (used in the unconstrained case), but also develops a more realistic assessment—the CERI Reference Case—based on likely timing conflicts, contingencies, and project delays and deferrals.

How have costs of production changed over the past year?
What is CERI’s long term view on oil sands capital and operating costs?
What impact does GHG emissions legislation have on costs?
What other cost areas have significantly changed?
How depressed natural gas prices impact oil sands costs could over the next decade, and what is CERI’s view of long term natural gas prices?
What are the implications for production levels and timing?
What are the implications for the economic viability of the oil sands?

The Impacts of Canadian Oil Sands Development on the United States Economy

October 2009

It is not a secret that Canada is one of the most important energy players in the world and the largest supplier of petroleum to the US—a fact that is often not realized. While other regions of Canada are attracting a lot of attention and offer tremendous potential for export, the heart of the Canadian industry is located in the western province of Alberta. It is well known that Canada’s most important energy resource is the oil sands, located predominantly in Alberta, but stretches into neighbouring Saskatchewan. With an estimated initial volume in-place of approximately 1.7 trillion barrels of crude bitumen, Canada’s oil sands are one of the largest hydrocarbon deposits in the world and provide the most secure supply to the US.

What are the impacts of a certain investment on output of goods and services, GDP, and employment? More specifically, what are the economic impacts of hydrocarbon developments on key macroeconomic variables such as output, GDP, and employment in a particular state? Is there any way to quantify those impacts? How can we study the impacts of such investments on macroeconomic variables in other states? As a result of investment in the oil sands, how many new jobs will be created in Ohio?

The Main Report is available for download.

Economic Impacts of the Petroleum Industry in Canada

Study 120

July 2009

The Issue

Last year was a tumultuous year to the say the least. The first half of 2008 saw a global rise in commodity prices, most notably oil and natural gas. The Canadian dollar appreciated against its US counterpart to levels not seen in decades. While certain sectors benefited from the rise of commodity prices and concomitant rise in currency values, others faltered. The second half of the year, however, saw commodity prices plunge dramatically, amidst a global financial crisis.

In the wake of these developments, the Canadian (and American) public is expecting policy-makers to set energy and environmental policies that make appropriate tradeoffs. However, to aid the process of rational decision-making and attitude towards the petroleum industry, policy-makers and business leaders require a clear understanding of the value and contribution of the petroleum industry to the economy. Their decisions will certainly impact the level of private investment and have wide-ranging effects across various, seemingly unrelated, industries. As the petroleum industry is frequently characterized by capital-intensive projects that generate single-purpose facilities, even small changes in policies may well have large impacts on investment levels.

The recent spate of publicity surrounding environmental impacts has overshadowed the fact that Canada’s petroleum industry is a significant contributor to the country’s GDP. The petroleum industry has widespread economic impacts that extend far beyond the province of Alberta–-Canada’s largest producer of oil and gas. Investments in new developments and expenditures in ongoing operations provide jobs that generate income-multiplier effects and economic spin-offs, benefiting the provincial and national economies.

The Research

The Canadian Energy Research Institute (CERI) conducted a comprehensive assessment of the role of the petroleum industry in the provincial and national economies, currently, and 25 years into the future. Utilizing an Input–Output (I/O) modeling approach, this study fills a knowledge gap that currently exists with respect to the quantification of the economic contribution of the petroleum industry, at the provincial, territorial, and national levels. The primary objective of this study was to measure the incremental impacts of the development in the oil and gas industry and the resulting impacts on the province, the other provinces and territories, and total Canada.

This timely and significant study sheds light on the Canadian petroleum industry and its importance to the Canadian economy, assisting both policy-makers and business leaders to make informed decisions regarding this industry. Furthermore, it informs the public about an important industry that is often misunderstood.

The Main Report and Summary Report are available for download.

Green Bitumen: The Role of Nuclear, Gasification and CCS in Alberta's Oil Sands
CERI Study 119
February 2009

The development of oil sands is a critical component in both the provincial and national economies. While oil sands development is expected to grow over the coming decades the amount of greenhouse gases (GHGs) emitted during the extraction and upgrading of bitumen is a drawback that left unattended could hinder development.

CERI has completed a multipart study that examined expected changes to Canada’s regulatory regime as it relates to the costs associated with emitting GHGs. These changes are expected to have significant impacts on current and future oil sands projects, in addition to upgraders that transform raw bitumen into synthetic crude oil (SCO). The impacts will initially be felt by operators and proponents as their supply costs are forced upward by the need for carbon mitigating equipment or alternative technologies that produce less carbon – such as nuclear or carbon capture and storage (CCS), with or without gasification of a hydrocarbon. Various scenarios are explored in this study as they relate to carbon costs, alternative technologies and the timeline for deployment of alternative technologies.

This study focuses on nuclear energy, gasification and to a degree CCS as the most likely methods to reduce or eliminate anthropogenic emissions as the first step on the road from Green Bitumen to Green Gasoline.

Summary Report

Part I - Introduction and Overview

Part II - Oil Sands Supply Cost and Production

Part III - Supply Costs of Alternative Fuels

Part IV - Alternative Fuels for Oil Sands Development Beyond 2020

The Eye of the Beholder:

Oil Sands Calamity or Golden Opportunity?

Oil Sands Briefing

February 2009

In light of all the uncertainty and pessimistic statements surrounding the future of the oil sands, the Canadian Energy Research Institute has decided to release an Oil Sands Briefing for industry, government, and members of the public to download.

The briefing provides insight into future production projections for the oil sands over the next decade and out to 2030, based upon several oil price projections and a global economic recovery. The briefing also considers the impact that reduced production could have on new capital spending in Alberta. “The CERI 2009 Economic Slowdown Projection indicates that C$218 billion will be invested in the oil sands for new production. This is C$97 billion less (the “loss”) than previously projected under the CERI Reference Case Projection (2008) and a shocking C$241 billion less than the CERI Unconstrained Projection (2008).”

Canadian Oil Sands Supply Costs and Development Projects (2008-2030)

Study 118

The recent unprecedented volatility in the price of crude oil and weakening global economy will have an impact on smaller companies proposing oil sands projects. When we couple the weak economy and volatile price of oil with continued rising costs for oil sands operators the mar gins for Greenfield producers are shrinking. Throw in the uncertainty pertaining to what the future price of carbon emissions could be and we have exciting, if not tense, times ahead for the oil sands industry.

Margins for producers are being absorbed by continued cost increases, much of which is due to professional and skilled labour, materials and equipment, and GHG emissions costs.

How much have costs of production continued to escalate?
What impact could future GHG emissions legislation have on costs?
What is the impact of the new royalty regime on costs?
What other cost areas have significantly changed?
What are the implications for production levels and timing?
What are the implications for oil sands supply cost and economic viability?

CERI calibrated the supply costs for the gamut of development systems—SAGD, cyclic steam stimulation (CSS), surface mining recovery, and bitumen upgrading—comparing updated costs with previous study results. Under current economic conditions, global oil prices need to be closer to C$90 WTI to support new prototypical oil sands projects over the next 30 years, with a high end of over C$100 per barrel WTI.

This CERI Report provides an up-to-date assessment. Our previous edition was a best seller; the new and significantly updated version.

The report will be of great interest for those involved directly or indirectly with the oil sands industry and professionals in government, investment banking, legal, and engineering and other support services sectors.

The Comparative Life Cycle Assessment (LCA) of Base Load Electricity Generation in Ontario

June 2008

The Canadian Energy Research Institute conducted this study in 2008 for the Canadian Nuclear Association (CNA). It includes a summary of key findings. The Main Report and Executive Summary are available for download.

The Economics of Significant Wind Power Development in Canada

Vol.1 Current Status of Wind Power in Canada and Selected Countries Table of Contents Vol. I

Vol.2 Levelised Unit Electricity Cost of Wind Power and Alternate Technologies Table of Contents Vol. II

Vol.3 Integrating Wind Power into Electricity Systems: Issues and Challenges Table of Contents Vol. III

In recent years increasing world-wide awareness and concern over air quality has created a move towards more environmentally friendly electricity generation sources such as wind power. In keeping with this broader global trend, interest in renewable sources of energy for electricity generation is growing across Canada, as provinces seek clean and cost effective alternatives to traditional generation from fossil fuels.

Wind power is one of the fastest growing energy sectors in the world, with annual growth rates averaging more then 25 percent for over a decade. In fact, Canada became only the twelfth country in the world to have installed capacity of wind power of more than 1000 MW (1 GW) last year. This growth is fueled by a combination of (a) cost reductions from economies of scale and technology alliances, (b) increased demand for emissions-free electricity, and (c) higher prices of alternate energy sources.

The development of wind power offers significant opportunities, as Canadians—individually and at all levels of government—make sustainable development and a clean environment a much higher priority. The quality of wind resources is specific to each location, and large-scale wind farms in Canada are only a recent phenomenon. The costs/benefits of wind power have yet to be fully defined. This CERI study provides a much-needed objective, independent and reliable assessment of the issues, examining the role of wind power development in Canada’s energy mix, and identifying the key costs and economics issues critical to understanding wind power as a viable alternative renewable energy source.

Did you know…?

The AESO has received expressions of interest in wind power totaling over 3000 MW? Some wind regimes in Alberta are cost competitive with Natural Gas?
There is a set of emerging best practices with respect to wind integration studies?
Integration costs depend on market structure, market penetration of wind power, and the overall portfolio of generation assets the system operator has to manage.

Oil Sands Production Outlook and Supply Costs: 2006 - 2030

“How much bitumen and synthetic crude oil will Canada be producing from the oil sands, and how much will it cost to supply it?”

This is one of the predominant questions being raised by industry and governments in Canada and the United States, as it concerns itself with energy security.

CERI provides an up-to-date evaluation of the likely production volumes from announced development projects (mining extraction, in situ recovery and bitumen upgrading), their energy requirements, and the associated supply costs of crude bitumen and synthetic crude oil streams, given recent market price changes. The analyses were conducted for two types of in situ recovery—CSS and SAGD—and for surface mining and extraction, for integrated mining, extraction and upgrading, and for stand-alone upgrading.

This report presents two production projections and their corresponding capital spending projections. The first is an Unconstrained case, which assumes all announced projects proceed on schedule and as planned. CERI developed a second, more realistic Constrained case supply projection that takes into account a number of limiting factors: capital spending, labour supply, market access, market uncertainty, material supply, environment, and regulatory access. This latter Constrained case results in an increase of gross bitumen production from 1.2 million barrels per day in 2006 to 3.8 million by 2020; a case that, given capital spending capability and annual capacity additions, is more attainable by the economy.

Ensuring Market Access: Capacity of the Western Canada Natural Gas Pipeline System

The Canadian Energy research Institute (CERI) is pleased to announce the public availability of the full report of Study No. 113: The Capacity of the Western Canada Natural Gas Pipeline System, with the release of Volume 2: Capital Costs and Pipeline Tolls.

Ensuring Market Access:

The Capacity of Western Canada’s Natural Gas Pipeline System

Peter Howard, David McColl, Dinara Mutysheva and Paul Kralovic

Volume 1 describes the Western Canada export pipelines, proposed pipelines from the Arctic, research methodology, four scenarios used in the study, key assumptions, and conclusions. Volume 2 details the capital costs and pipeline tolls associated with the system. The Summary Report for each volume provides a detailed overview. The following is a brief synopsis.

Natural gas production in western Canada keeps going at near-record levels, despite operating at times like a rapidly quickening treadmill. And there’s plenty more to come down the pipe—from Canada’s Mackenzie-Beaufort basins, Alaska’s North Slope, and Canada’s High Arctic. The natural gas is pipelined to consumers in Western and Eastern Canada, the US Mid-Continent, New England, and Mid-Atlantic States, and California and the Pacific Northwest.

System capacity - Five export pipelines connect the WCSB producing region with these demand locations. Together they have a total average annual daily export capacity leaving Alberta and BC of 14,980 MMcfpd (2005): the Duke Gas Pipeline (formerly the Westcoast system) at 1,100 MMcfpd; Gas Transmission Northwest at 2,770; Foothills/Northern Border at 2,180; Alliance at 1,630; and the TransCanada pipeline system at 7,210 MMcfpd.

The capacity of the TCPL eastern mainline will be reduced to 6,695 MMcfpd in 2009, when one of the gas pipelines is converted to oil service for the Keystone pipeline system. The TCPL East system currently has US market connections via of a number of pipelines—Great Lakes, Viking Gas Transmission, Iroquois, and Portland Natural Gas Transmission via TQ&M—as well as interconnections at Sarnia, Ontario, Niagara Falls, Ontario and other smaller nodes.

Pipeline contracts - The Alliance pipeline is operating under the primary term contract obligations that extend to 2015, with a provision that shippers may extend the service for a minimum of one year at a time by giving written notice five years in advance. The Northern Border pipeline contract expired in 2006, and it is currently operating under a combination of short-term firm service and interruptible contracts. The Gas Transmission Northwest, Westcoast Energy, and TransCanada pipelines are all operating under a combination of firm and interruptible contracts.

Supply and system utilization - The average utilization of these pipelines in 2005 was 83 percent. Gas Transmission Northwest had the lowest at 64 percent, and the Alliance pipeline the highest at 98 percent (including Authorized Overrun Service).

The EUB, CERI and the NEB all forecast a significant increase in the usage of natural gas in the Alberta Oil Sands sector that, coupled with a decline in production of conventional gas, will result in reduced deliveries to Alberta export pipelines (excluding the Alliance pipeline).

Coal Bed Methane development has increased over the past several years, and is forecast to continue an upward trend. LNG imports at Kitimat, BC (2009), and new gas deliveries via a Mackenzie Valley pipeline (2012), would also add to the supply availability. However, this is unlikely to be enough to reverse the declining trend. The current forecasts are for the average utilization of the export pipelines to decline from 83 percent currently to 74 percent in 2012 and 58 percent in 2018. This means that the unused take-away capacity would increase from its current level of 2,500 MMcfpd to 3,500 MMcfpd by 2012 and 6,900 MMcfpd by 2018.

System developments - TransCanada has proposed a 1,250 MMcfpd pipeline from northwest to northeast Alberta (the North Central Corridor). This would not contribute to Alberta export capacity, but does offer operational flexibility for intra-Alberta deliveries, negating the need to back-haul gas from the mainline to the Fort McMurray area.

The Mackenzie Valley pipeline, as it is currently proposed, will cost C$7.8 billion (2006 dollars, as in rest of text) for the pipeline connection from the Inuvik gas processing plant to the NWT/Alberta border. The average transportation tariff will be $2.42 per Mcf—$2.28 as a reservation charge plus $0.16 as a fuel usage charge.

The Alaska Highway pipeline is estimated to cost C$14.5 billion for the Alaska section and C$16.4 billion for the Yukon/BC section. The combined average transportation tariff for the gas pipeline from Prudhoe Bay, AK to Boundary Lake, AB will be $2.69 per Mcf—$2.50 as a reservation charge plus $0.19 as a fuel usage charge. The capacity design of the pipeline will be 4,500 MMcfpd delivered to Boundary Lake, AB.

Transportation costs - Transporting Alaska gas to Chicago by the Alliance pipeline system would require an additional C$2.6 billion for the connector pipe from Boundary Lake to Fort Saskatchewan, and an additional C$11.0 billion for incremental pipe and compression facilities on the Fort Saskatchewan to Aux Sable in Illinois. The combined average transportation tariff from Boundary Lake to Aux Sable will be $1.61 per Mcf—$1.27 as a reservation charge plus $0.34 as a fuel usage charge.

Transporting Alaska gas to Chicago via the TCPL Alberta, Foothills/Northern Border and TCPL East pipelines would require C$1.8 billion for additional pipe and compression facilities. These facilities are all required on the TCPL Alberta system; the export pipelines will have sufficient spare capacity to handle the additional volumes. The average transportation tariff for the TCPL Alberta/TCPL East and the TCPL Alberta/Foothills Northern Border systems would be $1.30 including the Alberta toll and fuel usage charge.

Keeping a lid on project costs - Comparing the size of the expansion projects required on the Alliance and TCPL systems, and understanding that construction would overlap the Alaska Highway activity, there is a strong potential for increased cost estimates and project cost overruns. It appears that expansion of the TCPL system would offer less of an impact on construction costs as a result of fewer facility requirements.

Alaskan gas to markets - Alaskan shippers would have access to multiple markets in the Pacific Northwest, California, eastern Canada, Chicago and the northeast United States. These would be accessed utilizing the existing infrastructure of the TCPL Alberta pipeline system, and connections with the Gas Transmission Northwest, Northern Border, TCPL East, Iroquois and others. It is difficult to quantify the value of access to multiple markets, but these connections would allow shippers to optimize flow direction, market deliveries, and, ultimately, product value.

Utilizing the spare capacity on the TCPL Alberta system and the associated export pipelines would not only mean significantly less contractual commitments from the Alaskan shippers, because of the minimal facility requirements, but would also offer the Alaskan shippers a 20¢-30¢ per Mcf toll saving compared with the Alliance expansion. This toll saving would also be realized by the existing shippers that transport gas from the WCSB to the eastern markets.

In this study CERI examined a broad series of scenarios using its proprietary models: CERI-PIPH for gas hydraulics; CERI-GASS for gas supply forecasting; and CERI-NPEM for equilibrium market price forecasting. The CERI research team—led by Peter Howard—believes that “the performance of the pipeline system into and out of western Canada is critical to efficient operation of the North American natural gas marketplace”.

Companies, government departments and regulatory agencies that understand the issues that CERI has examined and analyzed will be better equipped to take advantage of the business opportunities presented and facilitate operations. This Report is crucial to companies and organizations that want to see the big picture.

Socio-Economic Impact of Horseshoe Canyon Coalbed Methane Development in Alberta

CERI recently conducted a piece of research for some of the constituent entities in the coalbed methane (CBM) sector—the Alberta government, the gas producers and the unconventional gas scientific community—examining the economic impacts of developing CBM resources in central Alberta. The CBM resources—more formally known as natural gas from coal (NGC)—that are the first to be developed are in the Horseshoe Canyon formation, and are located in an area of central Alberta east of a line between Calgary and Edmonton. For its part, CERI conducted a socio-economic benefits analysis of the likely development scenario.

The project was conceived by the Alberta Ministry for Economic Development (AED), on behalf of the people of Alberta. The study was sponsored and funded by the Ministry, the Canadian Association of Petroleum Producers, and the Canadian Society for Unconventional Gas (CSUG).

A working group of geoscientists and engineers from CSUG first updated a predictive model for future Horseshoe Canyon CBM development. The research team as a whole developed the input assumptions required to evaluate the economic outcomes of various development scenarios for future Horseshoe Canyon CBM.

The Canadian Energy Research Institute (CERI) used these data and forecasts to evaluate the socio-economic benefits of Horseshoe Canyon CBM development using an economic impact assessment model. The model used by CERI is similar to the one previously developed for its evaluation of the economic impacts of developing Alberta’s oil sands—a study also made available to the public in late 2005.

The new CBM development socio-economic impact study—as well as the previous one on oil sands development impacts—can be downloaded from the CERI website. For further details of the study please contact Peter Howard, who was the CERI research project manager for the study.

Click here to download report.

Relative Costs of Electricty Generation Technologies

CERI was asked to update a graphical comparison of cost ranges for various generation technologies originally published in 2002 by Pollution Probe. As many of the original sources had not undertaken updates, CERI attempted instead to locate costs that to the extent possible had a common set of underlying assumptions.

The technologies considered in the cost comparison were nuclear, coal, natural gas, biomass cofiring (with coal), landfill gas, micro hydro, small hydro, large hydro, solar photovoltaic, solar thermal, wind, geothermal, and wave & marine. Although there was no clear winner, the two solar technologies stood out as having higher costs than the others.

Click here to download report.

Cogeneration Opportunities and Energy Requirements for Canadian Oil Sands Projects

Alberta's oil sands operators are an independent breed - the less they have to rely on anyone else the better. They need lots of steam and some electricity to produce the bitumen and/or synthetic crude oil - and would prefer their operations to be self-sufficient if at all possible.

Whether it is steam assisted gravity drainage (SAGD) or cyclic steam stimulation (CSS), in situ operators use large quantities of steam to reduce the bitumen viscosity to get it out of the ground. In surface mining operations, steam is needed to separate the bitumen from the mined oil sand. Then more steam is needed in the various upgrading processes.

They could build their own steam plants and get power from the grid, or they can cogenerate steam and power in a single facility - and the latter is just what many of them are opting to do. Co-generation of steam and electricity holds a potential benefit to Alberta's oil sands operators by both lowering energy costs and ensuring reliable supplies of electricity.

The various oil sands development plans announced to date would build to 4.2 million barrels per day (MMbpd) of bitumen and SCO production by 2020, if they were all to proceed. Even in CERI's more likely reference case, production reaches 3.2 MMbpd.

Some of the cogeneration projects built to produce steam generate more electricity than needed by the oil sands projects - and the surplus would go into the Alberta grid system. Oil sands operators, the grid system operator (AESO), merchant transmissions companies, electricity utilities, and large end-users alike need to understand the implications of all this cogeneration capability.

How much of a surplus generating capacity is planned?
When is it likely to be available?
What are the implications for transmission and the grid system operator?
How will all this extra electricity affect prices?
What are the economics? What is the potential impact on electricity prices?

The CERI research team believes that cogeneration of steam and electricity for oil sands developments "significantly impacts the availability of power in ALberta and the plans for other merchant generation facilities", as well as "AESO's responsibility for providing sufficient electrical transmission infrastructure to ensure that supply meets demand."

Significant oil sands co-generation capacity impacts all the players along the supply chain. Those organizations that understand the issues that CERI has examined and analyzed can position themselves to identify the business opportunities presented.

The Economic Impacts of Alberta's Oil Sands

Alberta’s oil sands reserves are second only to Saudi Arabia’s crude oil reserves—and the economic spin-offs are spread much wider than Alberta’s borders. Oil sands might be more expensive to develop than Saudi light oil—more capital investment needed and much higher supply costs—but that very fact means there is a greater multiplier effect on the Canadian economy.

Besides, increasing world oil prices, rapidly growing global demand for oil, and continuing advances in technology are all helping to reduce those cost differences. The increasing production levels of both crude bitumen and upgraded synthetic crude oil (SCO) are already—and will continue for many, many years—stimulating the economies of Canada and all its provinces, as well as economies abroad.

CERI has analyzed the potential economic effects of the ongoing development of Alberta’s oil sands, and presents its findings in this recently completed two-volume report. Our study spans the period 2000-2020—although the impacts continue well beyond. Three main impact areas are analyzed—gross domestic product (GDP), employment (including labour income), and government revenues—in several scenarios and with various sensitivities.

The CERI research team—led by Dr. Govinda Timilsina—has used sophisticated Input-Output models for Alberta, Ontario, Quebec, and the rest of Canada. The assessment uses CERI’s expected and potential oil sands supply outlook cases, and a series of sensitivity analyses.

Dr. Timilsina comments that, “in CERI’s relatively conservative base case scenario, investment of approximately $100 billion directly generates oil production worth about $570 billion—and in the process creates GDP increases of $885 billion, 6.6 million person years employment, and $123 billion of government revenues”.

He also adds, “these benefits are spread wide and far—Ontario, Quebec, other provinces, municipalities, and the various levels of government in Canada, as well as to other countries—and across many sectors of the economy”.

Given that the spin-offs from oil sands development in Alberta accrue widely to all parts of Canada and abroad, few, if any, governments and organizations can afford to ignore the issues CERI has examined and analyzed, if they want to position themselves to take advantage of the business opportunities presented.

Click here to download report.

Economic Impacts of LNG Imports to Atlantic Canada

North America’s natural gas marketplace has become extremely tight. North American domestic natural gas production is no longer increasing. Natural gas consumption, on the other hand, continues to be extremely strong. As a consequence, natural gas prices are at record highs. It is purely a matter of economics—supply and demand—and the marketplace mechanisms are at work looking for additional supply to meet what has proven to be a surprisingly inelastic demand. Arctic gas is till 5-10 years away—the pipelines will not be moving gas from the Mackenzie-Beaufort Basin or Alaska’s North Slope before the next decade.

Liquefied Natural gas—LNG—has long been seen as one of those external natural gas supply sources. LNG is now coming into its own after 30 years of promise. More than 90 percent of the world’s natural gas resources are outside North America and some of it can be brought to this market as LNG.

Canada’s Maritime and Atlantic Provinces are ready to play a significant role. The area is close to the US New England and Northeast markets. The area is not plagued by NIMBY constraints on infrastructure development to the same extent as most US areas.

This CERI study—which is jointly sponsored by PRAC (Petroleum Research Atlantic Canada)—therefore comes at an apposite time. The Report…

reviews of the proposed LNG projects in Nova Scotia, New Brunswick and Quebec
examines the Maritimes’ regional natural gas marketplace
assesses the markets in New England and beyond
determines the impacts of Maritimes’ LNG supply on those local and adjacent markets
considers the effects on the various pipeline systems locally, regionally and into the major markets of the US northeast, and
evaluates the overall impacts of these changes on the North American marketplace, including the effects on other major supply projects such as Arctic gas pipelines.

If you are involved in any aspect of the natural gas supply chain in North America you should have an understanding of the LNG sector—and what promises to be the first truly significant LNG supply increase in North America for a long time.

This Report is a “must-have” for those involved directly with the natural gas industry and its exploration to consumption supply chain, as well as professionals in the investment banking, legal, engineering and other support services sectors.

The Economics of High Arctic Natural Gas Development: Expanded Sensitivity Analysis

With the North American natural gas market experiencing a delicate balance between supply and an ever increasing demand, the price of natural gas has been surging. This has led to a need for the development of incremental sources of supply in North America, including the North Slope of Alaska, the Mackenzie Valley Corridor, the Mackenzie Delta/Beaufort Sea, and liquid natural gas from other parts of the world.

The Canadian Energy Research Institute has re-assessed the feasibility of High Arctic gas development. In particular, the analysis focuses on the 9 TCF of established natural gas located at Melville Island's Drake Point and Hecla fields. This analysis presents four Canadian delivery options (liquefied natural gas, liquefied natural gas transshipment, gas-to-liquids natural gas, and compressed natural gas) as an example of the potential future of High Arctic natural gas.

CERI is pleased to release the findings of its recently expanded sensitivity analysis on the economics of High Arctic natural gas development. We are also happy to acknowledge the sponsorship of the report by Indian and Northern Affairs Canada and the involvement of the Government of Nunavut. We thank them for their support.

Click here to download report.

Conventional Oil Development Information Session

The Alberta Department of Energy in coordination with the Canadian Energy Research Institute and the Alberta Energy and Utilities Board (EUB) hosted an overview information session on conventional oil development at the Sandman Hotel in Calgary, January 26, 2005.

Click here to view the presentation.

"CERI's supply study provides a reality check for oil sands industry"

In providing an independent and the most up-to-date assessment of bitumen supply costs and production forecasts, CERI's latest study answers the most important question currently posed by industry stakeholders what are the economic prospects for oil sands projects?

Recent developments including the strengthening of the Canadian dollar and higher natural gas prices have conspired with project cost over-runs and other issues to subject proposed projects to closer technical and commercial scrutiny than ever before.

CERI's economic analysis has concluded that many new projects will indeed proceed while others will require innovative solutions to mitigate downside risks including those brought about by the vagaries of crude oil prices.

The 200-page study entitled Oil Sands Supply Outlook: Potential Supply and Costs of Crude Bitumen and Synthetic Crude Oil in Canada 2003-2017 was released on March 3rd, 2004.

Download media presentation file click here

Levelised Unit Electricity Cost Comparison of Alternate Technologies for Baseload Generation in Ontario

This report provides a comparison of the lifetime cost of constructing, operating and decommissioning new generation suitable for supplying baseload power by early in the next decade. New baseload generation options in Ontario are nuclear, coal-fired steam turbines or combined cycle gas turbines (CCGT). Nuclear and coal-fired units are characterised by high capital costs and low operating costs. As such, they are candidates for baseload operation only. Gas-fired generation is characterised by lower capital costs and higher operating costs and thus may meet the requirements for operation as peaking and/or baseload generation.

Full Report...

Natural Gas in Canada and the United States - From Wellhead to Burner-Tip

CERI is pleased to announce the release of the latest edition of its popular introduction to the natural gas industry in Canada and the United States.

The new edition reflects the substantive changes that have occurred in the natural gas industry over the last decade. Changes include: competition in retail markets, new methods of pipeline regulation and the development of a secondary capacity market, the growth and restructuring of the merchant energy business, the development of natural gas off Canada's East Coast and the increased attention to resources in the Arctic as well as LNG. In addition, the original publication did not contain discussion of important geological aspects related to natural gas such as rock formation, stratigraphic intervals and traps.

Forecast Of Average Annual Power Pool Prices in Alberta

CERI has completed its October 2003 update of wholesale electricity prices for Alberta. The forecasts cover the period from 2004 to 2020. The update considers a Reference Case and a number of sensitivity cases. The Reference Case forecasts prices for a business-as-usual situation. The sensitivity cases include considering the effect on electricity prices of: lower natural gas prices; delivering more low-cost cogeneration from existing and planned oilsands development to central and southern Alberta; developing more coal-fired generating units to supply the system; and low and high electricity demand projections.

Does Nuclear Energy Have a Role in the Development of Canada's Oil Sands?

CERI recently completed a study for Atomic Energy of Canada (AECL) that compares the economics of a modified ACR-700™ Advanced CANDU Reactor with the economics of a natural gas-fired facility to supply steam to a hypothetical Steam Assisted Gravity Drainage (SAGD) project located in north-eastern Alberta. This paper presents the results of CERI's evaluation.

Potential Supply and Costs of Natural Gas in Canada

Canada's annual natural gas production increased almost 20 percent between 1995 and 2001. During that time Canadian gas satisfied continuing growth in domestic markets while increasing exports to the U.S. by almost a third. In 2002, the record of growth came to an end, as gas well completions fell by 17 percent and overall production began to drop. Despite higher prices and substantial increases in drilling in 2003, supply growth remains elusive. Does this mean the limit has been reached for conventional gas production from Western Canada, and what does the future hold for alternative sources of Canadian natural gas?

For a complete list of CERI publications, download the latest publication list.

Next >

North American Natural Gas Market Dynamics: Natural Gas Vehicles – A Review

Canadian Oil Sands Supply Costs and Development Projects (2010-2044)

Ensuring Market Access:

The Capacity of Western Canada’s Natural Gas Pipeline System

Peter Howard, David McColl, Dinara Mutysheva and Paul Kralovic

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