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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?

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 and industry operating costs.

For more information contact Roxanne Rees at (403) 220-2381 or rrees@ceri.ca, or download order form.

 

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. Printed copies are available for the price of shipping and handling, contact Roxanne Rees rrees@ceri.ca  for pricing.

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).”

This release follows a series of successful oil sands publications from CERI, and we hope that it will provide your organization with timely information relating to the oil sands and where we could go from here. Questions and comments can be directed to the author of the report, David McColl, dmccoll@ceri.ca.

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

CERI 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 margins 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.

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.

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.

 

For more information contact Roxanne Rees at (403) 220-2381 or rrees@ceri.ca, or download order form.

 

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.

 

For further information please contact: Marwan Masri, President & CEO, Canadian Energy Research Institute, mmasri@ceri.ca  or Colin Hunt, Director of Research and Publications, Canadian Nuclear Association,  huntc@cna.ca 

 

 

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.

Click here  to download order form.

 

For more information contact Roxanne Rees at 1(403) 220-2381 or rrees@ceri.ca

 
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.

Click here to download order form.  The price of the study report is C$5,000 + GST for members and non-members alike.

For more information contact Roxanne Rees at 1(403) 220-2381 or rrees@ceri.ca

 

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.

 

Contact CERI for more information:
Peter Howard, Vice President, Research
1 (403) 220 2379 or phoward@ceri.ca

 

Click here to download order form.

 
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.

 

For more information, contact Roxanne Rees at (403) 220-2381 or email.

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.

For more information, contact Roxanne Rees at (403) 220-2381 or email.

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.

For more information, contact Roxanne Rees at (403) 220-2381 or email.

Download order form

 

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.

For more information contact Roxanne Rees 1(403) 220-2381 or email.

Download order form

 
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.

More information….


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?