Page 1

SP EC IA LI ssue

ALBERTA UPGRADING OUTLOOK :: JANUARY 2011

Industrial Heartland group hopes to jump-start stalled value-added

COVER

oilsands expansion while producers turn south to new markets

MOMENT ALBERTA’S PLACE IN THE NORTH AMERICAN MARKET

Upgrader project status

Explaining BRIK

JANUARY 2011 :: OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK 1


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Headquartered In and Positioned to Serve Alberta’s Industrial Heartland Heartland is defined as “the part of a region considered essential to the viability and survival of the whole.” If you are doing business in Alberta’s Industrial Heartland, it makes sense to turn to a local company that understands the unique dynamics and needs of the area. Clients of Integrity Land have enjoyed the added value and success resulting from the company’s team members living and working in Alberta’s Industrial Heartland, on many completed and ongoing projects in the region. Proximity to these projects has been a crucial factor in building rapport and credibility with stakeholders, completing successful consultation, meeting community needs and keeping the schedules of projects on course, not to mention cost savings.

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board to handle all the land-related aspects. In conjunction with their facility expansion, Canexus once again looked to Integrity Land to acquire pipeline right-of-way from the newly proposed off-loading railway terminal. As a member of the Fort Saskatchewan Chamber of Commerce and through its close association with Alberta’s Industrial Heartland Association (AIHA), Integrity Land is involved in the local business community. Neil Shelly of the AIHA says, “Integrity Land is well known and widely respected here in the Heartland community.” With its presence in the Heartland, its expertise and reputation, Integrity Land claims that it is ready to fulfill its mission, for your company and team: “We provide exceptional service, ensuring advancement and success!”

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4 OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK :: JANUARY 2011


Editor’s Note ALBERTA UPGRADING OUTLOOK

There is truly no shortage of challenging strategic decisions that face producing companies wanting to play in Canada’s crude oil sandbox. One of the most significant conclusions these firms must make is how far their facilities will take what is essentially the most valuable dirt in the world down the value chain to useable consumer products. Inevitably, somewhere down the line Canada’s gooey gold becomes gasoline, jet fuel and the plastics that contribute to virtually everything we use and need. The question at hand is where this transformation should happen ­— because where it conceptually should happen and where it does and will happen are two very different things, each supported by very rational reasons. The problem is that these decisions do not exist in a provincial vacuum exclusive to Alberta. If they did, it is very likely that all oilsands production would be upgraded and refined to its lightest fractions and products right at home. But that is not how this works — at least not right now. Continental and even global market fundamentals say that heavy oil is trading too close to light oil to encourage Alberta producers to make the former the latter, and the trend is forecast to continue. In this special supplement to Oilsands Review we’re taking an in-depth look at this issue, which is a complex intersection of the needs of industry, community and government. The stakes are very high, not just for Alberta but for North America — after all, everyone is increasingly dependent on Canadian dirt.

president & ceo Bill Whitelaw

bwhitelaw@junewarren-nickles.com

publisher Agnes Zalewski

azalewski@junewarren-nickles.com

editorial director Stephen Marsters

smarsters@junewarren-nickles.com

editors Deborah Jaremko

djaremko@junewarren-nickles.com

Chaz Osburn

cosburn@junewarren-nickles.com

Editorial Assistance

Laura Blackwood

Janis Carlson de Boer

Marisa Kurlovich

proofing@junewarren-nickles.com

Contributors

Jim Bentein

Melanie Collision Darrell Stonehouse

creative Production, Prepress and Print Manager

Michael Gaffney mgaffney@junewarren-nickles.com

Senior Publications Manager Audrey Sprinkle

asprinkle@junewarren-nickles.com

Publications Manager

Rianne Stewart

rstewart@junewarren-nickles.com

Art Director

Ken Bessie

kbessie@junewarren-nickles.com

Creative Services Manager

Tamara Polloway-Webb

tpwebb@junewarren-nickles.com

Graphic Designer

Lyuba Kirkova lkirkova@junewarren-nickles.com

Creative Services

Martha Boctor

Janelle Johnson

production@junewarren-nickles.com

Contributing Photographers Charles Hope Aaron Parker Joey Podlubny

— Deborah Jaremko

CONTENTS

14

sales Director of Sales

Rob Pentney rpentney@junewarren-nickles.com

Sales Manager-Advertising Maurya Sokolon

Refining moment

Industrial Heartland group hopes to jump-start stalled valueadded oilsands expansion while producers and pipeliners turn south to new bitumen markets by Darrell Stonehouse

19

Outside INFLUENCE

msokolon@junewarren-nickles.com

Sales

Michael Goodwin

Producers view market conditions as best way of determining where upgrading and refining take place

Advertising Inquiries

adrequests@junewarren-nickles.com

by Jim Bentein

Ad Traffic Coordinator

Elizabeth McLean

atc@junewarren-nickles.com

22

From shovel-ready to TBD

North West’s upgrader is closest to starting construction

marketing

by Deborah Jaremko

Trade Show & Marketing

Jeannine Dryden

Coordinator

jdryden@junewarren-nickles.com

27

The basics of BRIK

Understanding the government program designed to spur upgrading and refining development

offices Calgary:

Edmonton:

2nd Floor, 816-55 Avenue NE

6111-91 Street NW

Calgary, Alberta T2E 6Y4

Edmonton, Alberta T6E 6V6

Tel: (403) 209-3500

Tel: (780) 944-9333

Fax: (403) 245-8666

Fax: (780) 944-9500

Alberta’s Industrial Heartland may provide the next step in environmental synergy and bitumen benefits

Toll-free: 1-800-387-2446

Toll-free: 1-800-563-2946

by Melanie Collison

Oilsands Review is owned by JuneWarren-Nickle’s Energy Group and is published monthly. GST Registration Number 826256554RT. Printed in Canada by PrintWest

by Darrell Stonehouse

30

34

ISSN 1912-5305 ©2011 1080552 Glacier Media Inc. All rights reserved. Publications

Environmental solution?

Q&A with Don Rigney, chair of Alberta’s Industrial Heartland Association

Mail Agreement Number 40069240. Postage paid in Edmonton, Alberta, Canada.

“What it really comes down to is jobs, pensions and benefits”

If undeliverable, return to: Circulation Department, 800 - 12 Concorde Place, Toronto

by Chaz Osburn

ON, M3C 4J2. Made in Canada. We acknowledge the financial support of the Government of Canada through the Canada Magazine Fund towards our editorial costs.

36

STATISTICS

Alberta bitumen and synthetic crude oil: production, processing and prices JANUARY 2011 :: OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK 5


PHOTO: Charles Hope 6 OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK :: JANUARY 2011


COUNTY OF THORHILD NO. 7

INDUSTRY Proponents of efforts to ensure that more bitumen is upgraded

STURGEON COUNTY

and refined in Alberta and that value-added petrochemical

ALBERTA’S INDUSTRIAL HEARTLAND

industries remain here point out that the long-term capital decisions made today will have a long lasting impact — for the province as well as the country. A wide range of industrial complexes helps make up Alberta’s Industrial Heartland,

PROPOSED HORSE HILLS ENERGY AND TECHNOLOGY PARK

LAMONT C

FORT SASKATCHEWAN

including the sprawling Shell Scotford facility pictured here. In fact, the Heartland Association says that since 1958, more than $23 billion has been invested locally by those companies.

STRATHCONA COUNTY EDMONTON

ELK ISLAND NATIONAL PA

SHERWOOD PARK

JANUARY 2011 :: OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK 7

CO BLACKFO RECR


PHOTO: Charles Hope 8 OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK :: JANUARY 2011


COUNTY OF THORHILD NO. 7

COMMUNITY Alberta’s Industrial Heartland is far more than

STURGEON COUNTY

Canada’s largest hydrocarbon processing region.

ALBERTA’S INDUSTRIAL HEARTLAND

It is also where thousands of Albertans make their homes. They live in cities like Edmonton, Sherwood FORT SASKATCHEWAN

Park and Fort Saskatchewan (shown here), and smaller communities and the rural areas of the counties of Lamont, Strathcona and Sturgeon. For those who call the Heartland home, quality of life is

LAMONT C

STRATHCONA COUNTY EDMONTON

of utmost importance.

ELK ISLAND NATIONAL PA

SHERWOOD PARK

JANUARY 2011 :: OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK 9

COO BLACKFO RECR


PHOTO: Charles Hope 10 OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK :: JANUARY 2011


COUNTY OF THORHILD NO. 7

GOVERNMENT Exporting or keeping bitumen in Alberta to be upgraded is

STURGEON COUNTY

more than an industry issue. It’s also a political one. Premier Ed

ALBERTA’S INDUSTRIAL HEARTLAND

Stelmach has said that exporting raw bitumen is like “exporting topsoil,” and many argue the provincial government should do more to encourage upgrading in Alberta despite discouraging market conditions. At the last Progressive Conservative annual

LAMONT C

FORT SASKATCHEWAN

meeting delegates voted overwhelmingly for the government to create more incentives and new legislation to ensure two-thirds of bitumen is upgraded at home.

STRATHCONA COUNTY

EDMONTON

ELK ISLAND NATIONAL PA

SHERWOOD PARK

JANUARY 2011 :: OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK 11

CO BLACKFO RECR


815840 Edmonton Economic Development Corp full page • fp

12 OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK :: JANUARY 2011


ALBERTA’S INDUSTRIAL HEARTLAND

While currently the majority of Alberta's bitumen upgrading capacity is located in the Athabasca oilsands region in the province's north, Alberta's Inudstrial Heartland region will play a key role in the sector's future.

AB

Redwater

STURGEON COUNTY 39 19 19 19

19 1

35

33

Maxim Deerland Peaking Station

19

38

Bon Accord

37

27

16

41

26

40

31

28

21

LAMONT COUNTY

23

36

19

Gibbons

11

CN Fort Saskatchewan Oil and Gas Distribution Center

18

2

15

3 5

40 42

20

19

25

CFB Edmonton Garrison (Namao)

FORT SASKATCHEWAN

12

ALBERTA'S INDUSTRIAL HEARTLAND ASSOCIATION LAND OWNERSHIP

7 Umicore Sulzer Metco Marsulex Smith & Nephew ATCO Midstream

Agrium Inc

15

Air Liquide Canada Ltd

2

16

ARC Resources

3

Aux Sable Canada Ltd (Heartland Off-Gas Plant) BP Canada Energy Company

17

ATCO Gas

4

Dow Chemical Canada ULC

18

CN Worldwide North America CP Rail

5

Keyera Energy Facilities Inc

19

6

Petrogas Energy Services Ltd

20

7

Praxair Inc

21

Gulf Chemical & Metallurgical Canada Corporation Kinder Morgan Canada Terminals LP

8

Sherritt International Corporation

22

King Tech Maple Resources

23

MEG Energy (Stonefell Terminals) Sunwest TransCanada Pipelines (Keystone Terminals)

LAMONT COUNTY

33 1

3

31

33

Alberta Sulphur Terminals

24

10

Altalink Ltd

25

11

Alter NRG

12

Canadian Heartland Real Estate Limited

13

Canexus Chemicals Canada LP North America Terminal Operation Triton Fabrication Inc

35

32

34 21

14

STURGEON COUNTY

31

30

ELK ISLAND

NATIONAL PARK

9

35

29

STRATHCONA COUNTY

1

STRATHCONA COUNTY

Strathcona Science Prov. Park 35

Lamont

5

DND Riverbend

EDMONTON

12 12

6

CITY OF FORT SASKATCHEWAN

Proposed Horse Hills Energy and Technology Park

14

CP Scotford Transfer Facility

18

4 8

40

9

13

41

17

35

2

1

10

Bruderheim

24

31 22

CN Sturgeon County Support Yard

19

Sherwood Park

STRATHCONA INDUSTRIAL ASSOCIATION LAND OWNERSHIP

26

Access Pipeline Inc

1

Agrium Inc

27

Evonik Degussa Canada Inc

28

Provident Energy Ltd / Williams Energy Canada Inc

EXISTING AND PROPOSED UPGRADER SITES COOKING LAKE BLACKFOOT PROVINCIAL RECREATION AREA

36

BA Energy Heartland Upgrader (postponed)

30

Air Products - SMR Hydrogen Production and Pipeline Supply Alberta Envirofuels (AEF)

37

Fort Hills Energy Limited Partnership (deferred)

31

Enbridge Pipelines

38

North West Upgrading Inc

32

Gibson Energy Ltd

39

Northern Lights Partnership (Total) (deferred)

33

Imperial Oil

40

Shell Canada Ltd (Scotford)

34

Pembina Pipeline Corporation

41

Statoil Canada (deferred)

35

Suncor Energy Inc

42

Total E&P Canada

29

BEAVER COUNTY

REFINERIES 1

1

2

3

4

5

6

7

8

8 KILOMETRES

Imperial Oil Strathcona

3

Shell Scotford

2

Suncor Energy Inc

SOURCE: Alberta’s Industrial Heartland Association JANUARY 2011 :: OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK 13


Refining mo Industrial Heartland group hopes to jump-start stalled

value-added oilsands expansion while producers and pipeliners turn south to new bitumen markets

PHOTOS: Charles Hope

by Darrell Stonehouse

1

2

3

PHOTOS Companies like Dow Chemical Canada rely heavily on Alberta’s natural resources for their operations. Dow’s Fort Saskatchewan manufacturing site forms one of the largest petrochemical facilities in the country. Dozens of storage tanks, such as these along Refinery Row west of Sherwood Park, are used for product at refineries operated by Imperial Oil and Suncor. Located about 40 km northeast of Edmonton, the sprawling Shell Scotford facility processes Alberta synthetic crude into products such as gasoline, jet fuel, diesel, propane and butane.

1

J

2

ust four short years ago, plans for turning ­Alberta’s Industrial Heartland into a worldclass petrochemical cluster based on refining large amounts of bitumen into clean fuels and other industrial feedstock seemed like a safe bet. Seven new upgrading projects were slated for construction in the region northeast of Edmonton, eventually expected to add processing capacity of 1.6 million barrels of bitumen per day. This, in addition to at least 225,000 barrels per day of upgrading capacity advancing at the time in the Wood Buffalo region, closer to production projects. Preliminary studies into creating a Heartland-region refinery and petrochemical cluster fuelled by the by-­ products from the upgraders looked positive. Then, it all fell apart. Industrial construction costs in Alberta spiralled out of control, causing developers to delay projects. The global economic crash of 2008 hit, and the upgrader projects that had previously been delayed began dropping out of the development cue. After the smoke cleared, by late 2010 only two Heartland projects remained — North West Upgrading’s 150,000-barrel-­­­per-day development and Total’s 200,000-barrel-per-day upgrader linked to its production facilities in Wood Buffalo. Emerging from the economic rubble, oilsands producers had begun looking for cheaper, less risky means than

14 OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK :: JANUARY 2011

3

building upgraders to offset the risk of the differential between light oil and bitumen prices. Partnerships with U.S. refiners were formed to expand capacity for upgrading, with bitumen producers offsetting their price risk through both financial agreements and agreements to upgrade bitu­men where pipeline connections allowed it. Pipeline companies seized the opportunity to advance plans to connect Alberta bitumen supplies to refin­ eries in the U.S. Midwest and Gulf Coast. Enbridge and ­TransCanada brought on over 800,000 barrels per day of transport capacity to the Midwest in 2010. TransCanada also launched an expansion of its just-completed Keystone pipeline, which will send around 375,000 barrels per day to refiners on the Gulf Coast.

GOING SOUTH MAKES CENTS The end result has been a narrow heavy oil differential, making it more profitable to sell raw bitumen stateside than to upgrade it at home. Seeing Alberta’s future as a world-class petrochem­ ical player headed down the pipeline to the United States, ­Alberta’s Industrial Heartland Association (AIHA) decided to act. In July, with partners from the construction and petrochemical industries, the association launched a public awareness campaign called Refine It Where We Mine It. The goal of the campaign is to get the public behind the idea that the


oment

government needs to intervene to encourage the development of four new upgraders in the province over the next 10 years. “The time to act is now,” said Don Rigney, mayor of Sturgeon County and AIHA chair. “Exports of raw bitu­ men are increasing much faster than the growth in Alberta’s upgrading capacity. We currently refine the lowest percentage of our production of any jurisdiction in North America. Through this public awareness campaign, we are calling on Albertans to show their support for increasing our capacity to upgrade Alberta’s natural resources here at home.” Rigney said around 70 per cent of current bitumen production is upgraded in Alberta. If no new upgraders are built and bitumen production continues climbing at present rates, that number will drop to 40 per cent by 2020. “It is a significant loss.” And that loss is quickly being cemented in place, according to a recent report by The Alberta Federation of Labour (AFL), a supporter of the Refine It Where We Mine It campaign. The report, called “Lost down the Pipeline,” says that while the global downturn halted expansion of upgrading capacity in Alberta, at U.S. refineries operators have been working full steam ahead in advancing growth plans. The AFL believes without aggressive government inter­vention, the upgrading business will permanently move south of the border.

The report points out that U.S. refiners are in the process of spending about $31 billion to build, retool or expand at least 10 refineries for the specific purpose of upgrading and refining raw bitumen from Alberta’s oilsands. These refineries will have the combined capacity to upgrade and refine about­ 2.8 million barrels per day of raw bitumen from Alberta. To put these numbers in context, output from the Alberta oilsands today totals about 1.5 million barrels per day. By 2020, Alberta’s bitumen output is expected to rise by to about 3.3 million barrels per day.

WHAT COULD BE ON THE LINE “What our research shows is that American refineries will have the capacity to process all of the expected increase in oilsands output from Alberta,” says AFL president Gil McGowan. “As a result, unless the government steps in much more aggressively than it has, the raft of upgrader postponements we’ve seen here in Alberta will almost certainly turn into permanent cancellations. We’ll be losing literally thousands of jobs down the pipeline.” The AFL report also looks at two solutions put forward by the Alberta government: new pipeline tolls and its scheme to collect bitumen in lieu of royalties to kick-start upgrading projects in the province. But it concludes that both are ineffective and doomed for failure. The report claims the provincial government has actually been undermining the real competitive advantage that would make bitumen upgrading and refining profitable in Alberta. »

THE CASE FOR UPGRADING AND REFINING IN ALBERTA: - It will create thousands of temporary and fulltime jobs - Other industries in the Industrial Heartland would benefit - Creates stability during boom and bust energy cycles THE CASE FOR EXPORTING BITUMEN TO THE U.S.: - Alberta doesn’t have the capacity yet to handle expected increase in bitumen - It’s expensive to build refineries and upgraders here - American refineries have excess capacity

JANUARY 2011 :: OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK 15


4

4

5

PHOTOS Air Liquide, which has had a presence in Alberta since 1920, operates a plant at the Scotford complex. Alberta’s Industrial Heartland is comprised of many industries, such as the Agrium (Redwater) plant, the largest fertilizer complex in North America.

5

The number of jobs, increased economic activity and increased potential government revenues on the line are huge, according to AIHA. Developing four new upgraders would result in 52,000 person-years of direct construction employment. It would create 4,000 permanent jobs in operations and an additional 12,000 dedicated jobs in supply, services and maintenance contracts. Around 11,000 person-years of work would be generated in engineering and design alone. The AIHA says that governments would benefit through a significant increase in corporate taxes, with the province capturing around $440 million per year and the federal government adding $780 million per year to its coffers. The Canadian chemical industry is also worried about bitumen being shipped south to U.S. refiners. Petrochem­ icals in Alberta generate around $13 billion in revenues annually, converting mostly ethane into polyethylene and other manufacturing feedstock. But as conventional nat­ ural gas production has peaked, ethane supplies have begun to dwindle. While new gas supplies are coming on stream from coal seams and shale deposits, they often lack the natural gas liquids needed to feed petrochemical plants. The industry believes that off-gases from bitumen upgrading can keep current operations running at full cap­ acity, while allowing for future expansion. At its annual meeting in August, the Chemistry Industry Association of Canada heard reports outlining the extent of the problem. It was revealed that the supply of petrochem­ ical ethane feedstock extracted from conventional natural gas was already below levels needed for the chemical industry to operate at full capacity. If nothing was being done to boost ethane availability, the group heard, Canada was headed for an ethane shortfall equivalent to the feedstock requirements of one major petrochemicals facility by 2020.

ETHANE ENCOURAGEMENT The Alberta government is working to encourage greater ethane extraction in the province through its ­Incremental Ethane Extraction Policy. The policy is also

16 OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK :: JANUARY 2011

designed to encourage off-gas capture from upgrading. Olefins-rich off-gases produced during bitumen upgrading are seen as a good replacement for declining ethane production. The chemical industry, however, believes that the policy didn’t provide enough incentive to encourage off-gas capture. Williams Energy is the only petrochemical operator in the province currently stripping olefins and natural gas liquids out of the upgrading processing stream. It has a plant at Suncor that collects off-gases that are then shipped to its olefin fractionation facility at Redwater, Alberta. The plant is capable of producing 14,000 barrels per day of olefins and natural gas liquids, which are sold across North America. The chemical industry believes that if Alberta is to grow more value-added petrochemical production from the oilsands, it needs help from the federal government as well as provincial incentives. One way the federal government could encourage upgrading is to re-institute the accelerated capital cost allowance (ACCA) it began phasing out in the 2007 budget. A temporary two-year ACCA program is in place, but upgrader projects are exempt. The Chemistry Industry Association of Canada would like to see the program made permanent with the oilsands part of that program. “It is important to note that upgrader projects in Canada do not qualify for the current temporary ACCA,” the association noted at its annual meeting last summer. “­Meanwhile, U.S. refineries are retrofitting to handle Alberta bitumen as they take advantage of a five-year ACCA that was put in place in 2007 by the U.S. government and recently extended to maintain a five-year planning horizon.” The accelerated capital cost allowance in the United States is only one factor among many why refineries there are expanding and taking more raw Alberta bitumen as feedstock. The cost of adding coking capacity to existing refineries rather than building new facilities is also favourable to U.S. upgrading expansion. Calgarybased consultants Strategy West put the price tag at 30–50 per cent less to add capacity in the United States compared with building new upgraders in Alberta.


“If we were just to ship raw bitumen, we would be doing a huge disservice to the next generation because we do have to add value in the province.” — Alberta Premier Ed Stelmach

But the new coking capacity is not being used to expand total refining capacity in the United States. The general consensus among analysts is that American oil demand has peaked, and oilsands exports are simply replacing dwindling supplies from other sources. The collapse in production from Mexico’s giant Cantarell field — where only 780,000 barrels per day of oil were produced in 2008 compared with 2.1 million four years earlier — has opened up refining capacity in the United States and ­increased demand for heavier crude. Similar supply ­problems from Venezuela have added to the demand, narrowing the heavy oil pricing differential.

A BREWING POLITICAL STORM Politically, it appears there is a growing storm brewing over bitumen exports in Alberta. The governing Progressive Conservative Party has pledged to target 68 per cent of bitumen to be upgrading in the province. Premier Ed Stelmach has said in the past that exporting raw bitumen is like “exporting topsoil.” In an effort to encourage more upgrading, the government launched its Bitumen Royalty In-Kind (BRIK) program, which will see it take its share of royalties in actual product and use it to encourage the construction of new upgraders. In May, it announced North West Upgrading (50 per cent owned by ­Canadian Natural Resources) would be its first partner in the BRIK program. The government is working on a deal with North West Upgrading. The government is also working to make pipeline tolls reflect the true costs of exporting bitumen down the pipe. However, the Progressive Conservative annual meeting in Calgary in late October showed there is a growing grassroots demand for the government to do more. Athabasca-Redwater Tory MLA Jeff Johnson introduced a discussion paper at the convention calling for the government to intervene to encourage more domestic upgrading. After an hour-long debate, delegates voted overwhelmingly for the government to create more incentives and new legislation to ensure two-thirds of bitumen is upgraded at home.

Stelmach appeared to support the effort, commenting, “If we were just to ship raw bitumen, we would be doing a huge disservice to the next generation because we do have to add value in the province.” Energy Minister Ron Liepert, however, said he had recently met with a spectrum of industry executives, and they believe getting government involved deeper in the oilsands would be a mistake. “There was not one of them who encouraged us to get in with both feet in the upgrader business,” Liepert said. He later added that he doesn’t expect the government to do much more in the way of encouraging upgrading. The other provincial political parties seem supportive of government action. In October, New Democrat leader ­Brian Mason visited Fort McMurray, Alberta, where he said the province should focus on getting maximum value out of the oilsands development for Albertans. “Our resources should not be creating wealth other places because we fill pipelines with raw bitumen heading away from Alberta,” Mason said. “The leases for development need to include guarantees of value-added processing taking place in Alberta.” The provincial Liberal Party tells a similar story. “It is in Alberta’s best interests to be more than a supplier of raw material,” reads the Liberal Party platform. “Adding value keeps skilled jobs, money and knowledge here at home. This is the principle behind the successful creation of Alberta’s petrochemical industry in the 1970s and ’80s. “We believe that adding value is important, and our target would be that current proportions of ­A lberta-based bitumen upgrading are at least maintained as oilsands development grows.” The Wild Rose Alliance Party has yet to release its­ ­platform on oilsands development. Industry will ultimately decide how much new upgrading capacity is built in the province. In the short term, at least, the answer appears to be not much.

GROWING CONCERN Output from the Alberta oilsands today totals about 1.5 million barrels per day. By 2020, Alberta’s bitumen output is expected to rise to 3.3 million barrels per day.

JANUARY 2011 :: OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK 17


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Outside influence

Producers view market conditions as best way of determining where upgrading and refining take place by Jim Bentein

may actually be a good thing that so many raw oilsands bitumen producers want to ship their product to be upgraded and refined in the United States, rather than first upgrading it within Canada, says one of the country’s top consultants to the downstream sector of the oil and gas industry. “As more raw bitumen flows to the U.S., there is a vested interest that that bitumen continue to flow there,” says Michael Ervin, vice-president and director of Calgary-based M.J. Ervin & Associates, a division of London, Ontario–based Kent Marketing Services. “It means those refiners have skin in the game.” Ervin argues that it will become increasingly difficult for state governments and Washington to implement policies to stem the flow of Canadian bitumen to the United States if more refining sector jobs are reliant on that flow. “It’s a pretty compelling reason to let the market decide,” he says. While he understands why the Alberta government wants to see more upgrading occur in the province, since upgraders create high-paying industrial jobs, he says it can’t be forgotten that the ultimate market for all of that crude now is the United States, which has multiple options to access foreign crude. There is excess upgrading and refining capacity now in the United States — in fact there’s an excess of both worldwide — so Ervin is skeptical about the need to add more to the mix. “It still comes down to the point of trying to target the winners,” he says, adding that upgrading and refining is a risky business, and ultimately the taxpayers will wind up paying more than is justified to kick-start the construction of upgraders within Alberta.

The Alberta government has implemented its Bitumen Royalty in-Kind (BRIK) program, which gives it the option of receiving royalties from producers in dollars or in bitumen of the same value. It would likely give upgraders within the province some kind of price break on the bitumen the province accumulates as a way of encouraging developers to build new facilities. Alberta Energy Minister Ron Liepert recently projected that the government could be handling as much as 400,000 barrels per day of bitumen by 2020. Ervin describes this approach as a “back door subsidy,” which is contrary to the Alberta government’s past approach of letting free markets determine where investment dollars go. He says the reality is, refining is a low-margin business, and upgrading is no different. In the 1960s Canada had 44 refineries. It now has 18 and, with plans by Royal Dutch Shell plc to close its Montreal refinery and to turn it into a storage facility, it will have 17. Yet Canada has double the refining capacity it did in the 1960s. There have been no new refineries built in the country since 1984 and Ervin says it’s unlikely there will be any others built. Meanwhile, dozens of refineries have also closed in the United States. Peter Boag, president of the Toronto-based Canadian Petroleum Products Institute, which represents those involved in the downstream sector, says a great deal of new refining capacity has been built in Saudi Arabia, Asia, Brazil and in other developing markets in the last few years, many of which have the capacity to upgrade heavier crudes. This, along with declining demand in the developed world, has put »

JANUARY 2011 :: OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK 19


“We are of the view the market should determine what approach is more economically efficient.” — Pius Rolheiser, Spokesman, Imperial Oil

great pressure on refiners in the United States and elsewhere in the developed world. “Demand for refined products will probably stay flat or decline in the next few years,” he says. “Meanwhile, there are new refineries being built in Asia and elsewhere and they all have export capacity. Refined petroleum products are, in the end, commodities and the cost of transportation is not that high.” He says his association “hasn’t been privy to the thinking of the Alberta government” regarding its efforts to encourage upgrading within the province, but that effort faces huge challenges. “It’s a tough business.”

An industry perspective Last spring, Imperial Oil sanctioned the first-ever oilsands mining pro­ ject to not include a dedicated upgrader. Instead, production from the 110,000-barrel-per-day first phase of Kearl will enter pipeline markets as diluted bitumen. Imperial will also not be retrofitting its Strathcona refinery to process larger volumes of heavier crude, citing that the economics simply aren’t there. “Imperial’s view is that upgrading involves huge capital investment and considerable economic risk,” says company spokesman Pius Rolheiser. “We are of the view the market should determine what approach is more economically efficient.” Rolheiser points out that Imperial is investing huge sums in the oilsands — it has spent about $2.3 billion in capital for its­­­ in situ operations at Cold Lake, Alberta, along with the $8 billion it

20 OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK :: JANUARY 2011

is spending at Kearl, while creating thousands of jobs. If it saw a need for developing domestic upgrading capacity, it would do so. “To this point, given our experience with marketing bitumen, we don’t share the view that developing upgrading capacity in Alberta is a good investment,” says Rolheiser. Rhona DelFrari, spokeswoman for Cenovus Energy, now Canada’s largest producer of bitumen using steam assisted gravity drainage (SAGD), says the company has no plans to develop its own upgrading capacity. However, it already indirectly owns upgrading and refining assets through a deal reached almost three years ago with ConocoPhillips, under which the two own equal shares of upstream and downstream oilsands assets. This includes the Foster Creek, Alberta, and Christina Lake, Alberta, SAGD projects upstream, and the Borger, Texas, and Wood River, Illinois, refineries on the downstream. “While we do jointly own two refineries with ConocoPhillips, downstream isn’t at all our focus,” says DelFrari. “Once we produce our oil, we simply sell it onto the market at one of the hubs. That business model allows us to get the best returns for upstream and downstream.” She makes it clear that Cenovus has no plans for upgraders in Alberta. “That is simply not our core business. Our focus is on oil production.” She adds that the company certainly doesn’t discourage others from investing in upgraders. “Regarding the province’s goal of increased upgrading and processing in Alberta, we believe any actions that provide increased demand for bitumen are good for the industry.”


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From shovel-ready to TBD North West’s upgrader is closest to starting construction by Deborah Jaremko

PHOTO: Charles Hope

North West Upgrading’s 150,000-barrel-perday development will be located on this site near the North Saskatchewan River in Alberta’s Industrial Heartland. 22 OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK :: JANUARY 2011


Three years ago, almost two million barrels per day of new upgrading capacity was planned for Alberta. Today, the proposed volumes have shrunk substantially, but multiple projects still exist at various stages in the development process. Here is a look at the status of those facilities.

In play: North West Upgrading Amid all the uncertainty and debate around upgrading oilsands production within Alberta, there is one company that is looking at the near-term with confidence. North West Upgrading, along with 50 per cent owner and partner Canadian Natural Resources, was selected in 2010 by the Government of Alberta as the operator that will process the province’s volumes of bitumen taken as royalty in kind. The site has been cleared as is “shovel ready” for its $4-billion, 50,000-barrel-perday first phase. North West Upgrading chairman Ian McGregor says that the contract with the government is in the process of being finalized, and the company still has to “go out and do a very large finan­ cing,” but he is confident that construction will start by the end of 2011. McGregor says operations would begin about 30 months after that.

Steps forward with uncertain timing Compared to 2007 — a year that Alberta’s Industrial Heartland Association executive director Neil Shelly has referred to as a “gold rush” — 2010 was very short on action relating to new Alberta upgrading projects. However, one of the world’s so-called supermajor oil companies passed a major milepost on the way to construction of a Heartland-area project, an installation that could eventually process up to 295,000 barrels per day. In mid-September, Total E&P Canada was granted conditional regulatory approval for its Strathcona Upgrader, which would be built in three phases. The company has in the past said that the first 150,000–barrelper-day phase, pegged at $8 billion, will start operation in 2014, which would likely mean for sanction in the near term due to the required yearslong construction period. However, upon the Energy Resources Conservation Board’s (ERCB’s) issuing of the approval, Total spokeswoman Saphina ­Benimadhu said Total needs to study the decision report before it determines its next steps, signalling that while the approval was significant, the energy giant has yet to commit to the development.

And there are other Alberta upgrading projects that remain on the table with a “TBD” in the column for their scheduled start-up date. This includes the suspended Suncor Voyageur project (about 125,000 barrels per day in its first phase), the next phase of Canadian Natural Horizon (approximately 115,000 barrels per day) and the next integrated in situ/upgrading steps for Nexen. The company has approval for a 60,000-barrel-perday second phase at Long Lake. “We remain committed to the value of upgrading integrated with bitumen development,” says Nexen spokesman David Coll. “However, our strategy going forward is to focus first on achieving reliable bitumen supply, upon which we can then match the construction of an upgrader. This approach takes advantage of learnings from Long Lake and allows important flexibility to adjust to evolving market conditions.” There is approximately 1.2 million barrels per day of upgrading cap­ acity that has already secured regulatory approval within Alberta, but not corporate sanction.

Withdrawn In fall 2010, Royal Dutch Shell became the latest oilsands producer to not only put its plans for new upgrading capacity within Alberta on hold but to withdraw them completely from the regulatory system. Shell did this just as commissioning began on a 100,000-barrel-per-day expansion at its Scotford Upgrader in Alberta’s Industrial Heartland. Shell’s withdrawl of the Scotford Upgrader 2 project application joins two other major projects taken out of the system in the last three years — ­multi-phase upgraders that would have been owned by Statoil and Total E&P Canada. The company says that rather than pursue approvals for new pro­ jects, it will capitalize on existing debottlenecking opportunities. “We have identified options for up to 85,000 barrels per day of ­debottlenecking potential that could be implemented in the next decade — effectively the volume equivalent of a new expansion but with the potential to pace the incremental steps with affordability,” » JANUARY 2011 :: OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK 23


“ We have learned from operational experience that we have capacity in our base plant upgrader, and we expect to see the same for the expansion plant. Our near-term debottlenecking focus is therefore essentially to provide more mining feedstock to fill the spare upgrading capacity.

— John Abbott, Executive Vice-President of Heavy Oil, Shell Canada

says John Abbott, Shell’s executive vice-president of heavy oil. “We have learned from operational experience that we have capacity in our base plant upgrader, and we expect to see the same for the expansion plant. Our near-term debottlenecking focus is therefore essentially to provide more mining feedstock to fill the spare upgrading capacity.” About three years ago, when Synenco Energy postponed the 100,000-barrel-per-day Northern Lights upgrading project, it was not because it could optimize its existing operations — it had none. And cost escalations in the superheated oilsands market had pushed the upgrader estimate to $10.3 billion. Junior Synenco could not afford it, and withdrew the application as it was going through the $478-million transaction to be acquired by Total E&P Canada. While Total con­tinues to progress the mining assets it acquired from Synenco through the regulatory process, as well as advancing its own upgrading project, the Northern Lights Upgrader remains off the table.

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Statoil’s proposed upgrader in Alberta’s Industrial Heartland met a similar fate, although not because it belonged to a tiny upstart — Statoil is an international energy company with operations in 34 countries. It put its 200,000-barrel-per-day Strathcona Upgrader on hold in spring 2008 and withdrew it altogether later that year, citing “prohibitive construction costs, the state of the global economy, uncertain oil price outlook and lack of legislative clarity.” The three projects (Shell, Synenco and Statoil) represent just over 700,000 barrels per day of upgrading capacity.

Where does upgrading start? Some Alberta oilsands producers are looking to manufacture a higher-value product than simple bitumen while circumventing the costly step of building an upgrader. While this may not provide a product comparable to light crude oil, it can take it steps closer to that important benchmark. Take for example Petrobank’s toe to

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heel injection (THAI) process, an in situ production technique designed to decrease reliance on water and natural gas, but also to provide a bitumen at surface that has already lost some of its heavy fractions underground. The Oil Sands Developers Group says that THAI has the potential to “result in a lighter, partially upgraded oil product being brought to the surface, meaning less life cycle [greenhouse gas] emissions overall, as it also reduces the amount of energy-intensive upgrading the produced oil has to undergo.” In announcing the latest results from its THAI production test at Conklin, Alberta, Petrobank reported that “produced oil has varied from heavy oil, consistent with the production wells being at the edge of the combustion zone, to upgraded THAI oil.” Partial upgrading is an important area of focus for in situ oilsands producers and research organizations, including the ­U niversity of Calgary’s In Situ Energy Centre, opened in early 2010. It is also being incorporated into the plans for the newest mining project for Alberta’s sandbox. Imperial Oil’s Kearl installation, a 110,000-barrel-per-day project that is currently under construction, does not include an upgrader, but it will provide a bitumen that has already undergone some treatment before entering market pipelines. This is thanks to Imperial’s paraffinic froth treatment technology, which starts the process of dropping out bitumen’s heavy ends. “This will allow us to produce pipeline quality bitumen without the need for an onsite upgrader,” says Imperial. “Processing bitumen once, rather than twice in an upgrader and refinery, reduces life cycle carbon dioxide emissions and development costs.”

Field upgraders — the quest for the best mousetrap continues While there has been a lull in development of large-scale upgrading projects in Alberta, three so-called “field upgraders” or smaller-scale on-site integrated plants that provide higher-end products, have recently progressed — looking to use proprietary technologies to battle the established concepts of economies of scale. In 2010, Value Creation Inc. (VCI) filed applications for two of these projects, Terre de Grace and Tri Star. Terre de Grace (which on the upstream end VCI is partnered with BP) would process about 10,000 barrels of bitumen per day, while Tri Star would be a 1,000-barrel-per-day demonstration. In fall 2010, another company filed its regulatory application for an integrated in situ field upgrader project, this one called Tamarack, owned by junior Ivanhoe Energy. Tamarack would be comprised of two phases of 20,000 barrels per day. “They are [both] attempting to target lower costs, and essentially trying to capture a different market segment,” says Purvin & Gertz sen­ ior vice-president Steve Kelly. “There is always a role for innovation. We are all anxious to see them succeed.”

Looking into the future Many analysts, including Purvin & Gertz’s Kelly, forecast that the market outlook for developing new upgrading capacity in significant quantities is not likely to change in the near future. The main issue is the light/heavy crude price differential. “A company looking at starting a new project would not be inclined to do so at this time,” says Kelly. “We’re seeing a pretty tight balance in demand for residue compared to supply. That suggests a narrow differential for the medium term at least.”

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JANUARY 2011 :: OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK 25


Alberta Upgrader Projects

Athabasca region

Industrial Heartland region

field upgrader

OPERATING PROJECTS Operator

Project

Capacity (bitumen bbl/d)

Capacity (products bbl/d)

Start up

Canadian Natural Resources

Horizon Phase 1

135,000

114,000

2008

Nexen

Long Lake Phase 1

72,000

58,000

2008

Shell Canada

Scotford Upgrader 1

155,000

158,000

2003

Suncor Energy

Base U1 and U2

281,000

225,000

1967

Millennium Vacuum Unit

43,000

35,000

2005

Millennium Coker Unit

116,000

97,000

2008

Syncrude

Status

Stages 1 and 2

290,700

250,000

1978

Stage 3 Expansion

116,300

100,000

2006

TOTAL

1,209,000

1,037,000

Scotford Upgrader expansion

90,000

91,000

2010

Heartland Upgrader Phase 1

54,400

46,300

TBD

Phases 2–3

108,800

92,600

TBD

Canadian Natural Resources

Horizon Tranches 2–3

135,000

118,000

TBD

Nexen

Long Lake Phase 2

72,000

58,500

TBD

On hold

North West Upgrading

North West Upgrader Phases 1–3

150,000

139,200

TBD

NWU now owned by Canadian Natural Resources, in discussions to process government of Alberta bitumen royalties

UNDER CONSTRUCTION Shell Canada REGULATORY APPROVAL BA Energy (Value Creation Inc.)

Suncor Energy

Total E&P Canada

Construction suspended Sept. 2008

Fort Hills Phases 1–3

340,000

290,000

TBD

On hold

Voyageur Phase 1

156,000

127,000

TBD

Construction suspended Jan. 2009

Voyageur Phase 2

78,000

63,000

TBD

Strathcona Upgrader Phases 1–2 and debottlenecking

295,000

271,000

TBD

Approval granted Sept. 2010.

TOTAL

1,389,200

1,205,600

Tamarack Phase 1

20,000

n/q

2013

Application filed Nov. 2010

Tamarack Phase 2

20,000

n/q

TBD

Terre de Grace Pilot

10,000

8,400

TBD

Application filed Dec. 2007

TBD

Application filed Jun. 2010

APPLICATION FILED Ivanhoe Energy Value Creation Inc.

TriStar Demonstration

1,000

840

TOTAL

51,000

n/q

Shell Canada

Scotford Upgrader 2 Phases 1–4

400,000

391,000

Withdrawn Oct. 2010

Statoil Canada

Stratchona Upgrader Phases 1–2

250,000

217,000

Withdrawn Dec. 2008

Total E&P Canada

Northern Lights Upgrader Phases 1–2

113,200

101,200

Previous owner Synenco withdrew in Jun. 2008. Total bought Synenco in Aug. 2008.

TOTAL

763,200

709,200

Canadian Natural Resources

Horizon Tranche 4

145,000

125,000

TBD

Nexen

Long Lake Phases 3–6

288,000

234,000

TBD

Syncrude

Stage 3 Debottleneck

46,500

40,000

TBD

Stage 4 Expansion

139,500

120,000

TBD

TOTAL

619,000

519,000

APPLICATION WITHDRAWN

PROJECT ANNOUNCED

26 OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK :: JANUARY 2011


The basics of

BRIK Understanding the government

program designed to spur upgrading and refining development by Darrell Stonehouse

T

hree years after the Alberta government launched its ­Bitumen Royalty In-Kind (BRIK) initiative — an effort to encourage upgrading and refining raw bitumen within the confines of the province — there is a growing chorus of concern the program isn’t enough to launch the oilsands industry down the path toward becoming a world-scale petrochemical player. The province announced in 2007 that it would take bitumen instead of cash for a share of its royalties and use that bitumen to spur upgrading and refinery development. Two years later, it put out a Request for ­Proposals (RFP) to industry, furthering the BRIK effort. Last May, North West ­Upgrading was announced as the first potential partner in the initiative. Negotiations are now underway to build the refinery project in Alberta’s Industrial Heartland, northeast of Edmonton. The 150,000-barrel-perday refinery proposed by North West Upgrading will be built in three stages and will also include the application of newer technologies and an integrated carbon capture and storage capability to reduce CO2 emissions. Processing of the bitumen will go beyond upgrading to synthetic crude oil to include higher value products such as diesel fuel. Once completed, North West Upgrading will process 75,000 barrels per day of royalty in-kind bitumen on behalf of the province. Canadian Natural Resources, which owns half of North West Upgrading, plans to supply 12,500 barrels for Phase 1 of the development. Negotiations on the processing arrangements were expected to conclude before the end of the year — as this publication was going to press — with construction beginning on the first 50,000-barrel-per-day phase early this year. Operations would begin around 2013. Oilsands stakeholders say that while the BRIK program is welcome, more needs to be done to ensure that Alberta’s value-added industry keeps growing. The Alberta Federation of Labour (AFL) has been a critic of the initiative since the government sent out its RFPs in July 2009. AFL president Gil McGowan said the first RFP, for 75,000 barrels per day of bitumen “was a drop in the bucket compared to 1.4 million barrels of bitumen currently produced in the province.” Alberta’s Industrial Heartland Association (AIHA) agrees with this assessment. »

JANUARY 2011 :: OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK 27


“If we don’t act now, the new bitumen that

Providing diluent services to the oilsands sector

will be coming on line in the next few years will be processed

elsewhere.

— Alberta’s Industrial Heartland Association

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“While the Alberta government has shown vision and strong leadership by implementing the BRIK program, it will only get us a part of the way to our full potential,” the association noted in a news release announcing its Refine It Where We Mine It public awareness campaign. “The current BRIK program has the potential to build one new merchant upgrader. To reach the goal of adding value to the industry in a way that is sustainable, we need to upgrade two-thirds of the bitumen from the oilsands, and that requires that we build four upgraders in Alberta by 2020. Other programs that complement and support BRIK must also be implemented.” The provincial government expects to put out future RFPs every two or three years going forward to encourage more upgrading in the province. By 2020, it expects to have as much as 400,000 barrels per day of bitumen to market through the BRIK program. But the AIHA argues by the time those upgraders are built, it will likely be too late. “Once companies make decisions regarding where our bitumen will be upgraded, they are set in place for decades,” it noted. “To secure investments with pipeline companies and U.S. refining operations, companies sign long-term supply contracts. This means if we don’t act now, the new bitumen that will be coming on line in the next few years will be processed elsewhere.” Many in the provincial government recognize time is running out. At the Progressive Conservative annual meeting in late October, a resolution was passed that says the BRIK program is not meeting the province’s need and that more regulation is needed to keep more bitumen upgrading and refining in the province. The AFL says the answer to turning the current trend of bitumen exports around can be found in the past, specifically the 1970s when then-premier Peter Lougheed used the heavy hand of government to launch the province’s now $13-billion-per-year petrochemical industry. Lougheed made the removal of natural gas liquids mandatory before gas could be exported from the province to assure feedstock for the fledgling petrochemical industry. His government also used government money from the Heritage Fund to drive growth in the industry. The AFL wants to see the current Progressive Conservative government use regulations to prohibit the export of raw bitumen, and use government resources to create a publicly owned energy company with a mandate to advance the interests of Albertans. It also recommends that the government take the lead in building an upgrading and refining “super complex” based on a government-commissioned blueprint.

28 OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK :: JANUARY 2011


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ENVIRONMENTAL

SOLUTION? Alberta’s Industrial Heartland may provide the next step in environmental synergy and bitumen benefits by Melanie Collison

B

uilding the future of Alberta’s Industrial ­Heartland is like solving one of those wooden Chinese puzzles where the whole structure depends on fitting together the interlocking pieces in just the right order — but in this case doing it while blindfolded and wearing boxing gloves. The goals behind progressing bitumen upgrading, refining and further value addition inside Alberta are not just economic. Pans and studies show that many environmental benefits can be achieved through the regional co-­habitation of a variety of processes that ultimately provide useful market products on a broad scale. The eco-industrial principle behind the Heartland is that co-located facilities share infrastructure and therefore take less as a whole from the environment, requiring less total land and water, and emitting less waste of various kinds than if each were a stand-alone plant. While this collaboration already exists to a certain extent in the central Alberta / Greater Edmonton region, the full potential of the Industrial Heartland remains unfulfilled, and is faced with many unknowns. That’s what makes it tricky to optimally fit the pieces into this 582-square-kilometre complex, which fans out into Strathcona, Sturgeon and Lamont counties from Fort Saskatchewan, northeast of Edmonton. “There’s uncertainty regarding how much growth and development there will be,” says Neil Shelly, executive director of Alberta’s Industrial Heartland Association (AIHA). Partners in the non-profit AIHA are the City of Fort ­Saskatchewan, the three counties and the City of Edmonton, which officially joined in 2010.

30 OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK :: JANUARY 2011

LOOKING TO THE FUTURE To achieve the desired environmental efficiencies requires a concrete understanding of the future. For example, Shelly says, “You have to design a water system to handle seven or eight plants…but there’s no guarantees they’ll all get built. You could spend a lot of money building a water system that is way oversized for what the development might be.” More than 40 different industrial facilities exist in the ­Industrial Heartland today, including bitumen upgrading and refining plants — a sector that Shelly and others would like to see feature more prominently in the cluster. Four years ago, the future of the Heartland as a hub for bitumen upgrading and refining was hopeful and seemed relatively secure, with a list of billion-dollar projects marking milestones on their progression to successful development. But the viability of upgrading in Alberta hit a major snag in 2008 as the bottom fell out of the global economy and the market dynamics of pushing bitumen production as far as possible up the value chain within Alberta diminished to the point of oblivion. The hopes of the Heartland region were not the only casualty — ­north of Fort McMurray, oilsands giant Suncor Energy suspended construction on its new Voyageur upgrader, the beginnings of which still sit bare and wanting beside the highway as a poignant reminder of what was not — at least, not yet. The reactivation of the Voyageur upgrader project remains uncertain, but to the south, in the Greater Edmonton region, AIHA is taking heart from seeing the provincial government leaning towards squeezing more value out of its natural resources. The province is encouraging upgrading in Alberta by using raw barrels from its Bitumen Royalty In-Kind program »

2


1

1. CO2 is captured from the upgrader’s hydrogen manufacturing units. 2. An absorber vessel uses an amine solvent to capture the CO2. 3. The CO2 is dehydrated and compressed for pipeline transport. 4. The CO2 is pipelined to a nearby deep saline aquifer for storage.

1

CO2 Capture at Shell Scotford: the proposed Quest project

SCOTFORD UPGRADER

Image: Shell Canada

Shell Canada’s Scotford Upgrader in Alberta’s Industrial Heartland plans to take advantage of the opportunities for carbon capture and storage presented to it by being in a centralized location.

AMINE UNIT & COMPRESSOR

HYDROGEN UNIT

1

The Quest project is designed to capture up to 35 per cent of the upgrader’s CO2 emissions. Pending final approvals, it would be built to start-up in 2015. 2

When Suncor Energy merged with Petro-Canada in August 2009, it acquired the former Crown corporation’s Strathcona Refinery, which Petro-Canada had just completed reconfiguring to process 100 per cent oilsands feedstock. Located in the Industrial Heartland, in many ways the facility is an example of the benefits of co-locating upgrading and refining facilities. The AIHA’s Neil Shelly argues that clustering industrial development in the Industrial Heartland makes sense because it “enables collaboration on state-of-the-art centralized operations, whether it is water treatment or greenhouse gas reduction.”

CO 2

H2

H2

2

3

4

CO 2

AMINE UNIT

COMPRESSOR

PHOTO: JOEY PODLUBNY

JANUARY 2011 :: OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK 31




“ WE HAVE THE POTENTIAL TO DEVELOP NOT ONLY A WORLD-SIZE VALUE-ADDED DEVELOPMENT, BUT ONE OF THE GREENEST HYDROCARBON DEVELOPMENTS IN THE WORLD.

— Neil Shelly, Executive Director, Alberta’s Industrial Heartland Association

“as a leverage tool to incent more value added in Alberta,” Shelly says, adding that growing government clarity will give industry a chance to start putting into place all these synergies from which the environmental benefits can be derived.

BENEFITS OF CLUSTERING “Clustering all of the industrial development allows for an integrated approach to common requirements.” Besides shrinking the amount of land allocated for roads and rail access and the number of electrical transmission lines webbing the landscape, clustering enables collaboration on state-ofthe-art centralized operations, whether it is water treatment or greenhouse gas reduction. Shelly says that government support, such as the $2 billion Alberta is putting into carbon capture and storage, means that “we can get stra­ tegically critical infrastructure put into place in the next 10 or 20 years.” For example, the proposed Alberta Carbon Trunk Line system that would snake through the Heartland, “has the potential of turning it into one of the world’s ready carbon capture and storage areas,” he says. “People may come to the area because they can plug in,” Shelly says. “It’s common infrastructure, so large-cost CO2 transportation is feasible. A common system for disposing of CO2, water, everything, allows for higher efficiencies, so they can afford to put in more expensive high-quality facilities.” As well as reducing waste emissions, integrating facilities reduces resource uptake, including water use. Instead of a dozen or more stand-alone facilities incorporating costly individual water processing

Adding value to Alberta’s resources at home ensures a brighter future for all Albertans

778491 NorthWest Upgrading Inc 1/2h • hp

www.northwestupgrading.com

32 OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK :: JANUARY 2011


facilities, together a central water treatment plant could be built that uses leading-edge water treatment technologies on the way in and the way out. “Waste water coming out of one plant may be useful for another,” Shelly says. “It may be used five or six times before it’s returned to the river or evaporates.” Similarly, heat produced as a by-product of power generation can displace burning natural gas to heat buildings. In addition to being a cost-efficient way to reduce carbon emissions, cogeneration avoids wasting water in the form of steam, and allows flue gas components to be used as petrochemicals feedstock by a neighbour. “Nowadays, you see cooling towers with a whole bunch of evap­ orated steam,” Shelly says. “It’s low-grade heat or energy, but it’s still enough heat to warm a building. A combined heat and power centre uses residual heat in a district system and displaces natural gas use.” Other kinds of waste produced in one facility can also be used as feedstock by another — sulphur refined out of crude oil is used to make fertilizer; off-gases released during bitumen processing are building blocks that can be used by petrochemical plants. These synergies are already underway, but their scale could be greater. “We have the potential to develop not only a world-size value-added development, but one of the greenest hydrocarbon developments in the world,” Shelly says. “New operations can put in the newest technologies. We can look at other clusters, pick and choose best management practices and bring them into effect here.” But there are those who argue that the Heartland is not ready for mass development of this nature.

NOT SO FAST The Pembina Institute, an Alberta-based sustainable energy think tank, believes that it is premature for regulators to approve new industrial plants when the province has not yet completed the gargantuan task of writing cumulative effects regulation for the area. “There is certainly a lot of evidence that you can actually reduce the total level of impact if you have an integrated complex versus stand-alone refineries and chemical plants,” acknowledges Simon Dyer, oilsands program director at the Pembina Institute. However, he says that “without regional limits to protect the environment, cumulative development is a bad idea.” Cumulative impact regulations are under construction as part of the province’s ambitious series of watershed-based land-use frameworks, as directed by the Land Stewardship Act. In the meantime, there is “nothing to inform decision making, but we have an approval process that isn’t waiting for planning,” Dyer says. “That’s responsible for a lot of criticism. Planning is not keeping pace with development. Companies won’t wait and they won’t go above and beyond what’s required by the regulatory authorities. Carbon capture and storage is too expensive to do voluntarily at mine and upgrader [sites].” That’s precisely the problem the Industrial Heartland seeks to address with its eco-industrial vision and its lobbying for provincial involvement. “By approving a plant that has lots and lots of emissions, you rob yourself of other opportunities,” Shelly says. “They are starting to look at [cumulative effects regulation], but it’s going to take a while to flip it around and determine how to manage it.”

AlbertA’s source for fAsteners

820026 Fastenal Canada Company 1/2h • hp Acheson 780.960.4120

Airdrie 403.948.1347

Brooks 403.501.5244

Calgary Foothills 403.235.5802

NE Calgary 403.291.3282

Calgary Centre 403.258.2658

Clairmont 780.567.3200

NW Edmonton 780.443.1290

N Edmonton 780.482.2338

SE Edmonton 780.490.1330

SW Edmonton 780.432.6717

Fort McMurray 780.714.2000

Leduc 780.980.6230

Lethbridge 403.317.3140

Lloydminster 780.875.1850

Medicine Hat 403.504.5593

Red Deer 403.314.0588

Whitecourt 780.706.8899

Fort Saskatchewan Location

Now Open!

JANUARY 2011 :: OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK 33


Q&A with Don Rigney, chair of Alberta’s Industrial Heartland Association

“What it PHOTO: AARON PARKER

really comes down to is jobs, pensions and benefits.

Don Rigney wears two important hats in Alberta: one as mayor of Sturgeon County north of Edmonton and the other as board chair of Alberta’s Industrial Heartland Association. The association is a non-profit cooperative group of five municipalities “dedicated toward sustainable eco-industrial development” in Canada’s largest hydrocarbon-processing region — a region where some of the world’s largest petrochemical, chemical, oil and gas companies do business. It is also the group that last July launched the “Refine It Where We Mine It” initiative, a public campaign designed to build support for the oilsands value-added chain, starting with more upgrader development throughout Alberta. In an interview, Rigney talked about the creation of the initiative and why it is important.

34 OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK :: JANUARY 2011

What was the thinking behind the creation of the Refine It Where We Mine It initiative? It wasn’t too many years ago that there were plans to build nine upgraders and our future was secure. It seemed to be just a given that it was going to happen. But since 2006, we’ve gone from [plans for] nine upgraders in the Edmonton region to zero or hopefully one — North West Upgrading/Canadian Natural Resources Ltd./province’s ­Bitumen Royalty In-Kind [BRIK] program to at least ensure the provinces royalty barrels are upgraded in Alberta. They’ve either been cancelled or postponed or postponed indefinitely. In fact, what we’ve seen since November 2006, when the premier made the statement that exporting raw bitumen would be like stripping our topsoil, we’ve added exports — ­announced, committed or under construction — of close to a million barrels a day, depending on how you look at the numbers. At the same time, [although] the Shell upgrader is being completed, there are no new upgraders currently being built. So our concern was that the province’s stated goal of refining and upgrading two-thirds of our production was very quickly going to fall to 40 per cent. And that’s recently been confirmed by the ERCB [Energy Resources Conservation Board]. Alberta currently refines the smallest proportion of its production


and not purely capitalistic economy. — Don Rigney, Chair, Alberta’s Industrial Heartland Association

of any jurisdiction in North America. At the same time, the public perception is that everyone’s doing fine and things are good. We felt we had to raise awareness that this, in fact, is just not the case.

“The reality is we live in a mixed

as there are in the auto sector. I haven’t been able to verify this, but the source was credible.

Why is the timing of this initiative important? In addition to the Industrial Heartland Association, who supports the initiative? We’re very fortunate to have some very good partners. We felt we needed to get a wider audience and bring it to their attention. They’ve responded by signing on. We’ve got the Alberta Building Trades Council and Merit Contractors Association. I think that’s a first, because we’ve got both union and non-union shops. As well, we were able to get the Chemistry ­Industry Association of Canada because their big concern is they’re not seeing adequate feedstock to keep their facilities running and some may have to shut down. It’s a Canadian issue — I think they’re having the same issue in Sarnia [Ontario]. As well, we’ve got huge support from the newest member of the Heartland Association, Edmonton and the Edmonton Economic Development Corporation.

What are the economic benefits of upgrading in Alberta? It will enhance royalties. It will enhance GDP and all the other areas of our economy. But what it really comes down to is jobs, pensions and benefits so our kids and grandkids can live, work and play in this great province we call home and not follow our raw resource to the U.S. Midwest or Gulf Coast to find work.

Should the average Canadian be concerned about this issue? In terms of the tax revenue generated by these projects, 5 per cent goes to the municipality, roughly 40 per cent goes to the province and 55 per cent goes to the federal government. When we send, say, $9 billion a year to Quebec, a big part of that comes from the wealth generated by our resources. We’ve seen a dramatic drop in gas revenue, and it looks like that’s going to be with us for some time with gas in the $4–$5 range. We’re now seeing where the ­royalty revenue generated from bitumen is exceeding natural gas. With value-added industry and upgraders, we stabilize those income streams. In the past five years, these multi-billion-dollar upgrading facilities continued to run 24/7 even when light oil fell below $40 per barrel and heavy oil fell as low as $4–$8 per barrel. That’s significant for our economy and our revenue streams — it stabilizes things. Exporting raw commodities subjects us to the vagaries and uncertainties of wildly fluctuating raw commodity price swings. Additionally, when I was in Ottawa in May, I was told there are as many direct jobs in Ontario building components for value-added industry and upgrading

Once decisions are made to build pipelines to export raw bitumen, that’s a commitment that’s good for probably 35–50 years. So it doesn’t matter what the economics swings are — the product is going to flow south in its raw form. But if we mine, say, an amount of oil that contributes $25 billion to the GDP, we know that if we upgrade it we’ll add another $25 billion, then if we go to refined product we’ll add ­another $25 billion. We triple the economic benefit to all Albertans. We also get a significant benefit from constructing the facilities here.

How do you rectify the view that market forces should dictate where bitumen is upgraded — after all, that’s capitalism — with the view that government support is needed? The government has a role to play. Most of us know the government has played a significant role, direct and indirect, in the development of value-added industry in Alberta. Currently, there are some significant tax advantages and incentives offered in the [U.S.] Gulf Coast. It’s not a level playing field. Also, we do not have a free and efficient pricing market mechanism for bitumen. I am a strong proponent of free markets and free trade, but oil is probably the least “free” market-driven commodity on earth. Look at OPEC [the Organization of Petroleum ­Exporting Countries], the National Oil Companies and the big integrated oil companies. They [large integrated companies] can mine in Alberta and upgrade and refine across the border in the U.S. This enables them to take their profits out wherever in the chain that is most beneficial to them. We can’t play by Alfred Marshall’s neoclassical rules of economics where oligopolies and cartels exist. So I think we have to tailor our policies in light of these market realities to ensure we secure the most value from our resources for our citizens. I applaud the government’s BRIK program and recent selection of North West Upgrading and Canadian Natural Resources to build Alberta’s next upgrader in the Heartland to upgrade Alberta’s royalty barrels. There is overwhelming support for this but some opposition because of the perception the government is “getting into business” or the government is “interfering or intervening in the free market,” which I don’t believe it is. Regardless, we are only talking a drop in the barrel — 75,000 barrels per day of new upgrading capacity versus increased exports of raw bitumen of between 719,000 and one million barrels per day — hardly a massive market intervention. The reality is we live in a mixed and not purely capitalistic economy.

JANUARY 2011 :: OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK 35


250.0 200.0

STATISTICS

Alberta bitumen and synthetic crude oil: production, processing and prices

150.0

Series1 100.0 Alberta Synthetic Crude Oil Production

Production (10 3 m 3/d)

200.0

Synthetic Crude Oil

0.0 ’99

150.0

’01

’03

’05

’07

’09

’11

’13

’15

’17

100.0

Source: ERCB

50.0

250.0

Alberta has been producing synthetic crude oil (SCO) since 1967, when Suncor started the ‘19first commercial oilsands operation. SCO — ­the product of upgrading — is essentially a crude oil that has been manufactured to become as valuable as conventional light crude, which is declining in supply.

50.0 0.0 ’99

’01

’03

’05

’07

’09

’11

’13

’15

’17

‘19

500.0

Non-upgraded Bitumen Exports

400.0

SCO Removals from Alberta Alberta Demand

300.0 How much non-upgraded Canadian crude oil is exported to the United States has become a key issue for the oilsands industry and its stakeholders locally and continentally. Non-upgraded bitumen exports already exceed upgraded bitumen exports, and the trend is expected to widen further.

200.0 100.0 0.0 ’99

’01

’03

’05

’07

’09

’11

’13

’15

’17

‘19

418913 Bantrel Co 1/4h • tqc www.bantrel.com

36 OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK :: JANUARY 2011

Source: ERCB

Demand (10 3 m 3/d)

Alberta bitumen and synthetic crude oil demand and exports


from Alberta

REMAINING ESTABLISHED RESERVES UNDER ACTIVE DEVELOPMENT

Alberta Demand

25.2

3,000

18.9

In Situ

2,000

12.6

1,000

6.3

0

Mineable

0

’83

’85

’87

’89

’91

’93

’95

’97

’99

’01

’03

’05

’07

’09

Total

Source: ERCB

4,000

Reserves (billion barrels)

Reserves (10 6 m 3)

Alberta’s remaining oilsands reserves under active development

Alberta’s certified bank of oilsands bitumen that is on its way to development, produced as a potential feedstock for upgraders and refineries, grows as more projects get developed. This chart shows Alberta’s proved reserves at about 25 billion barrels, but the province is estimated to hold as much as 171 billion barrels of recoverable bitumen.

Canadian light/heavy oil differential, 2000-2010

Heavy Oil Average Price

90.00

Differential

$ / bbl

70.00

The light/heavy oil price differential is the key determinant of the economic viability of including upgrading capacity in an oilsands project or building a stand-alone upgrader. It is the difference in realized prices for heavy oil versus light oil (par, in this case, which is the average realized price for conventional Canadian crude as posted by major Canadian refiners).

50.00

30.00

10.00

’00

’01

’02

’03

’04

’05

’06

’07

’08

’09

‘10

This balance is currently very tight and is not expected to widen in the near future, making upgrading an unattractive economic prospect.

522820 Progress Land Services Ltd 1/4h • tqc Proud to be part of the development of Alberta’s Industrial Heartland Ph: 1-866-454-4717

www.progressland.com JANUARY 2011 :: OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK 37

Source: Oilsands Review

Par Average Price


ADVERTISERS’ INDEX Alberta’s Industrial Heartland Association���������������������21 Almita Manufacturing Ltd.��������������������Inside Front Cover APEGGA����������������������������������������������������������������������������������38

Value-added Processing is Key to Growing Alberta’s Resource Based Economy

Bantrel Co��������������������������������������������������������������������������������36

Converting Alberta’s resources into finished products in Alberta provides growth in employment, economic diversity, stable revenue streams and positive benefits necessary to sustain and build all of our communities.

Building Trades of Alberta����������������������������������������������������� 4 Edmonton Economic Development Corp�������������������������12 Fastenal Canada Company������������������������������������������������� 33 Integrity Land����������������������������������������������������������������������������3 Keyera Energy�������������������������������������������������������������������������28 Meridian Specialties Inc������������������������Inside Back Cover

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Nalco�����������������������������������������������������������������������������������������18 North West Upgrading Inc�������������������������������������������������� 32 PCL Industrial Management Inc�������Outside Back Cover Progress Land Services Ltd������������������������������������������������� 37 Sturgeon County��������������������������������������������������������������������38

sturgeoncounty.ab.ca

Town of Redwater������������������������������������������������������������������ 25

A proud member of Alberta’s Industrial Heartland

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38 OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK :: JANUARY 2011

www.apegga.org


501724 Meridian Specialties Inc full page • fp INSIDE BACK COVER

JANUARY 2011 :: OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK 39


515606 PCL Industrial Management Inc full page • fp OUTSIDE BACK COVER

40 OILSANDS REVIEW / ALBERTA UPGRADING OUTLOOK :: JANUARY 2011

Oilsands Review Special Issue - January 2011  

There is truly no shortage of challenging strategic decisions that face producingcompanies wanting to play in Canada’s crude oil sandbox. On...

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