Oilsands Review July 2015

Plus: Oilsands producers and contractors lay down the rules for diminishing change order culture

21 Industry welcomes new tailings framework as the AER suspends Directive 074

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contents VOLUME 10 | NUMBER 7 | JULY/AUGUST 2015

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6 IN REVIEW

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11 EYES ON THE OILSANDS

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37 UPCOMING EVENTS

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38 SECTOR WATCH

COVER FEATURE

FOLLOW THE MONEY Despite a stall in growth capital, producers are expected to spend more on maintenance and operations through 2017 as new projects come online

By Jim Bentein and Deborah Jaremko

12 FEATURES

20 A BETTER MEASURE

Industry welcomes Alberta’s new tailings management framework as the government suspends Directive 074

By Melanie Collison

23

CENTRAL AND DIVERSIFIED Alberta’s Industrial Heartland Association leaders focus on a future that doesn’t depend on oilsands upgrading

By Melanie Collison

OILSANDS DATA

COLUMN

24 PROJECT STATUS

The comprehensive listing of Canada’s oilsands developments

17 Oilsands producers and contractors lay down the rules for eliminating—or just reducing—change order culture

By Joseph Caouette

Alberta’s new tailings management framework is encouraging, but skepticism about regulation compliance is justified

31 STATISTICS

Taking a close look at the inputs to and outputs of the oilsands industry

Look for special coverage tagged with this logo:

THE IMPOSSIBLE DREAM?

35 TRANSITION

By Erin Flanagan

ON THE COVER:

Extra coverage only on our website.

Please share & recycle this fine magazine.

A new report from CanOils identifies the growing market for small and sustaining capital projects and maintenance, repair Plus: Oilsands producers and

and operations.

contractors lay down the rules for diminishing change order culture

21 Industry welcomes new tailings framework as the AER suspends Directive 074

ILLUSTRATION: JEREMY SEEMAN

JULY / AUGUST 2015 | OILSANDSREVIEW.COM

3

PROFIT FROM YOUR OIL SANDS OPERATIONS It helps to have a partner on your team that understands the local landscape. With CB&I, you gain the value of an established provider to the oil sands market, especially in mining extraction plants, SAGD and heavy oil upgrading facilities.

We believe that early contractor involvement in the planning stage aids immensely in the success — and profitability — of a project. Once CB&I is on board, we can provide fully integrated services across the breadth of a project, including FEED studies, modular fabrication and assembly, and full EPC. Furthermore, CB&I designs with a focus on constructability, allowing us to control and deliver projects with cost and schedule certainty.

Contact CB&I to learn how we can make your next oil sands project a safe and on-schedule success.

TECHNOLOGY FRONT END ENGINEERING DESIGN ENGINEERING, PROCUREMENT AND CONSTRUCTION MODULAR AND PIPING FABRICATION COMPLETE STORAGE SOLUTIONS

A World of Solutions Visit www.CBI.com

EDITORIAL

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EDITOR

Deborah Jaremko | djaremko@junewarren-nickles.com

editor’s note INSIGHTS INTO OILSANDS TRENDS

ASSISTANT EDITOR

Joseph Caouette | jcaouette@junewarren-nickles.com CONTRIBUTING WRITERS

Jim Bentein, Melanie Collison, Erin Flanagan EDITORIAL ASSISTANCE MANAGER

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Jordhana Rempel

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New oilsands project sanctions may have flatlined as the market navigates the uncertain duration of the price collapse, but activity is far from a standstill. In recent months, we have seen the start-up of at least five new SAGD facilities—including the massive 110,000-bbl/d Surmont Phase 2. Commissioning is under way on the second 110,000-bbl/d phase of the Kearl mine, and construction continues on several other major projects.

It’s all because, for the most part, oilsands project returns are viewed in a different context than most other energy plays.

Several years of work and investment underpins the delivery of these new facilities, and they all but promise to provide decades of stable production on a large scale. Most if not all of them will be finished, and in the short term, that may be all we can hope for. New projects need a clear line of sight to higher realizations, and that just doesn’t exist right now.

The good news is that what does exist is the continued growth in investment to support increased operational capacity. We know that the installed base of oilsands production capacity has doubled in the last decade. We also know that between 2015 and 2017, more than 700,000 bbls/d of new capacity will come online.

“This has created a dynamic market for companies supporting small capital projects, sustaining capital projects and maintenance, repair and operations,” reads a new CanOils market intelligence report. “Despite delays in new project development, this market is expanding.”

That means, CanOils suggests, that material opportunities exist for service and supply companies facing shortfalls from new oilsands capital investment to pivot their strategy to capitalize on growing maintenance outlay.

There also appears to be growing recognition that in order to deliver the innovation required to reduce both operating and capital costs in the oilsands, producers and their vendors must work together differently. This means working more collaboratively, with a more vibrant industry as their common goal.

As one oilsands producer recently noted, it can be easy to become complacent when times are good, and it is when times are hard that agility and transformation can break through. As companies work to reduce costs while in aggregate spending more, the opportunity exists to generate game-changing practices. It’s happened before, and I know it can happen again.

EDMONTON

Deborah Jaremko |

220-9303 34 Avenue NW | Edmonton, Alberta T6E 5W8 Tel: 780.944.9333 | Fax: 780.944.9500 Toll-free: 1.800.563.2946

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SR | djaremko@junewarren-nickles.com

Follow Deborah Jaremko on Twitter:

@oilsandseditor

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Web extras with the July/August 2015 edition

If undeliverable, return to: Circulation Department, 2nd Flr-816 55 Avenue NE, Calgary, Alberta T2E 6Y4. Made in Canada.

Is a fully integrated regional Athabasca water management system feasible?

The opinions expressed by contributors to Oilsands Review may not represent the official views of the magazine. While every effort is made to ensure accuracy, the publisher does not assume any responsibility or liability for errors or omissions.

Faces of the oilsands 2015

JULY / AUGUST 2015 | OILSANDSREVIEW.COM

5

in review JULY/ AUGUST 2015 // ROUNDING UP THE LATEST OILSANDS NEWS

ALBERTA’S NEW NDP CABINET INSTALLED: MEET THE OILSANDS PLAYERS

Shannon Phillips, minister of environment and sustainable resource development Phillips represents the southern Alberta riding of Lethbridge-West. Raised in Edmonton, Phillips graduated with honours from the University of Alberta with a master’s degree in political science. She previously worked as a journalist and consultant before taking a position with the Alberta Federation of Labour as an economic policy analyst.

Alberta’s fledgling NDP government took its first steps toward policy execution in late May as Premier Rachel Notley announced her 12-member cabinet. Here are the figures that will feature prominently in issues related to oilsands development, including the planned royalty review.

Joe Ceci, minister of finance and president of the treasury board Joe Ceci represents the riding of Calgary-Fort. He served as a Calgary city alderman for 15 years, winning five consecutive terms. He holds a master’s degree in social work from the University of Calgary and has served neighbourhoods in east Calgary as a community worker.

6

OILSANDS REVIEW | JULY / AUGUST 2015

Lori Sigurdson, minister of innovation and advanced education and minister of jobs, skills, training and labour Sigurdson represents the riding of EdmontonRiverview. A social worker with over 20 years of experience, she served as vice-president of Public Interest Alberta and manager of professional affairs for the Alberta College of Social Work before being elected. She holds a bachelor’s degree in political science from the University of Alberta and a master’s degree in social work from the University of Calgary, where she later served as an instructor.

Additionally, Sigurdson has taught at MacEwan University and Norquest College.

Kathleen Ganley, minister of aboriginal relations Before being elected to the legislature as the representative for Calgary-Buffalo, Ganley was a lawyer with the firm McGown Johnson, specializing in labour and employment law. She earned a Bachelor of Science degree in psychology, a bachelor’s degree in philosophy and a Juris doctor from the University of Calgary. She was awarded the Silver Medallion in philosophy and served as a clerk in the Provincial Court of Alberta.

PHOTOS: ALBERTA NDP PARTY

Rachel Notley was sworn in as the 17th premier of Alberta on May 24.

Marg McCuaig-Boyd, minister of energy McCuaig-Boyd represents the northern Alberta riding of Dunvegan-Central Peace-Notley. Before being elected to public office, she was a teacher and administrator with the Peace River School Division for more than 20 years, then moved on to become vice-president of Grande Prairie Regional College’s Fairview campus. In June 2013, McCuaig-Boyd left the college to start a consulting company to support small- and medium-sized businesses.

Addressing concerns about her lack of connections in Calgary energy boardrooms, she said, “I’m very collaborative, I’m very pragmatic [and a] great listener. My door is going to be open. It’s all going to be open and transparent as we move along, so [industry members] don’t have to worry.”

$20 million

AMOUNT PENGROWTH ENERGY IS INCREASING ITS CAPITAL SPENDING AT ITS LINDBERGH PROJECT IN RESPONSE TO CONCERNS THE NEW ALBERTA GOVERNMENT MAY BRING IN CARBON PRICING.

2.3:1 THE INSTANTANEOUS STEAM TO OIL RATIO ACHIEVED AT BAYTEX ENERGY’S SOON-TO-BEDECOMMISSIONED GEMINI SAGD PILOT.

$109 million

SIZE OF CONTRACT AWARDED TO AECON GROUP TO DO SITE ERECTION WORK ON THE STURGEON REFINERY PROJECT.

Husky achieves first production at Sunrise, realizes drilling efficiencies First production began at Husky Energy’s Sunrise project in mid-March. Steaming is underway on 34 of 55 well pairs, with strong facility performance reported.

Volumes are currently averaging 2,500– 3,000 bbls/d, and production is expected to ramp up steadily towards full capacity of about 60,000 bbls/d around the end of 2016. Systems have been filled and shipping is under way.

A new custom mobile drilling rig spudded the project’s initial well and has already demonstrated improved drilling efficiencies. The rig also provides for closer spacing of wellheads, smaller drilling pads and fewer pad facilities.

This, along with the incorporation of new technologies such as multi-phase metering, will result in well-cost savings of about 30 per cent compared to the initial pads.

A schematic of Shell’s Carmon Creek vertical steam drive project in the Peace River region. The project is now expected to start production in 2019 versus the original 2017 schedule.

PHOTO: SHELL CANADA

Shell delays Carmon Creek project start-up Shell Canada says it has decided to adjust the schedule of its Carmon Creek thermal oilsands project in the Peace River region in order to optimize the design of the facility and re-tender some contracts.

“We are still early enough in the schedule to make adjustments to ensure the long-term competitiveness of a project that will ultimately have a lifespan of more than 30 years,” says spokesman Cameron Yost.

“This revision should result in an improved cost structure and will likely push the full ramp up of the project out by a couple of years, looking at first oil in 2019,” Yost says, adding that Carmon Creek remains a priority and Shell is continuing to advance the project.

Shell officially sanctioned the Carmon Creek project in October 2013. Yost tells Oilsands

Review that construction is ongoing, although as part of the rescheduling, there will be some reorganization of construction efforts. Some elements of construction will go ahead while others will be pushed back.

It’s worth noting that the decision wasn’t driven by the low oil price, Yost says.

“We have a very strong balance sheet, we are integrated across the value chain and we take a long view as oil and gas projects typically have 30- to 50-year investment horizons,” he says.

“We know prices will fluctuate during that time.

The current market downturn does, however, create an opportunity to find some cost reductions on the Carmon Creek project.”

First steam achieved at ConocoPhillips Surmont 2, Athabasca Oil Hangingstone Two new SAGD projects are now officially operating, as ConocoPhillips Canada and Athabasca Oil recently achieved first steam at their respective facilities.

ConocoPhillips reported the on-schedule start of first steam at Surmont Phase 2 on May 29. The company had expected first steam by mid-year. Production is expected to ramp-up through 2017, adding approximately 118,000 bbls/d of capacity. Total gross capacity for Surmont 1 and 2 is expected to reach 150,000 bbls/d. ConocoPhillips has not reported the project’s final cost.

Meanwhile, junior Athabasca Oil achieved first steam at its 12,000-bbl/d Hangingstone SAGD project at the end of March. The company says the project was completed on schedule and the final cost estimate of $740 million to $750 million was within approximately five per cent of the sanctioned budget. Athabasca expects to reach design capacity by late 2016.

JULY / AUGUST 2015 | OILSANDSREVIEW.COM

7

in review ROUNDING UP THE LATEST OILSANDS NEWS

Pengrowth boosts capex for Lindbergh after commercializing Phase 1 Pengrowth Energy is boosting its capital spending at Lindbergh by $20 million, in part because the company feels engineering work for Phase 2 of the thermal project should account for carbon pricing regulations that might be initiated by the newly elected Alberta NDP government.

“In light of the change in government, we are spending more time looking at carbon capture

The Sturgeon Refinery construction site in fall 2014.

Aecon contracted to do site erection at Sturgeon Refinery Aecon Group will be doing additional work on the Sturgeon Refinery project as part of a new $109-million contract with the North West Redwater partnership.

Under the contract, Aecon’s energy segment will perform site erection work at the refinery project, including structural pre-assembly of modules, modular-to-modular interconnections and installation of mechanical equipment and instrumentation.

Work is expected to start in the second quarter of 2015 and be completed in the third quarter of 2016.

Aecon has already done structural steel erection, fabrication and module assembly at the project as part of a $230-million contract awarded last year.

Canada and the U.S. announce next generation of rail cars for flammable liquids The Canadian and U.S. governments have unveiled a new class of rail tank car for flammable liquids such as crude oil and ethanol. According to Transport Canada, the new standard—a “considerable improvement” over previous tank car standards—is the result of collaboration on both sides of the border.

“This will translate into better protection for communities in both countries,” Transport Canada says. “The new TC-117 tank car will be jacketed and constructed with thicker steel, thermal protection, a full head shield, top fitting protection and a new bottom outlet valve.”

The regulations establish the prescriptive and performance requirements to retrofit a tank car, as well as the retrofit schedule for DOT-111 and CPC-1232 tank cars used to transport flammable liquids.

8

OILSANDS REVIEW | JULY / AUGUST 2015

Transport Canada says that the new standard is a considerable improvement over previous tank car design.

PHOTOS: (TOP LEFT) CHRISTINA RYAN; (TOP RIGHT AND BOTTOM RIGHT) JOEY PODLUBNY

Pengrowth president and chief executive officer Derek Evans.

and what would be required in that regard to ensure we are doing everything we possibly can, as we believe the carbon tax or rate on carbon will likely increase as we go forward,” says Derek Evans, president and chief executive officer.

He adds, “Co-generation is probably the most efficient way for us to capture carbon today at the plant, and so that is part of that ongoing evaluation.”

The company declared Lindbergh’s first phase commercially open on April 1 and the project was achieving 10,500 bbls/d during the first five days of May. With strong initial production results, Pengrowth is also increasing capital spending to accommodate increased costs and project specification changes associated with tapping into the Husky Energy sales line, Evans says.

“There have been some spec changes on the pipeline in terms of size and in terms of insulation that were not previously part of the cost estimate. We have also had some inclement weather that has created some challenges for us getting that pipeline into the ground. We are still on track, but our costs would have gone up a little bit there.”

Pengrowth previously budgeted $200 million towards capital expenditures for this year, of which the company spent nearly half in the first quarter.

According to management’s financial and operational results, capital spending should increase to between $220 million and $240 million for the full year.

Operations at the two-well pilot project continue to show strong results, averaging 1,640 bbls/d in the second quarter, with an instantaneous steam to oil ratio of 2.4:1.

Southern Pacific’s STP-McKay SAGD project goes into hibernation; Baytex decommissions Gemini pilot

IDE Technologies hosted oilsands owner and vendor executives for a tour of its completed first horizontal evaporator unit for SAGD field use in Calgary this spring.

PHOTOS: (TOP) IDE; (BOTTOM) JOEY PODLUBNY

IDE moves towards field trial of horizontal evaporators for SAGD Global water treatment operator IDE Technologies has completed the fabrication of two horizontal evaporator units that will be installed in the oilsands this year.

IDE has been working with project owners to modify its horizontal evaporators for Alberta, with support from the Government of Israel and Alberta Innovates—Technology Futures and Alberta Innovates—Energy and Environment Solutions (AI-EES), which has contributed $2 million to the upcoming field test.

According to Vicki Lightbown, manager of water and environment with AI-EES, the two IDE units will be installed at an operating commercialscale SAGD project.

“It’s not your typical trial that is run for a certain period of time and then taken off line. These will continue to operate, but the scale just isn’t the scale that you would see when it is considered fully commercial.”

IDE says the technology can provide a 30 per cent energy reduction for water treatment, which Lightbown says would be significant.

“The trick with SAGD water management is finding a technology that balances maintaining a high recycle rate but [also] reduces energy requirements and greenhouse gas emissions,” she says.

“This is one of those technologies where evaporators can handle a more saline input source and still maintain a high recycle rate, but at a lower energy penalty. That’s the real benefit with this one, especially as more SAGD facilities are moving away from a freshwater makeup to more of a saline or brown water makeup.”

Gilad Cohen, IDE’s head of industrial water treatment, says the company has been working to perfect the technology for use in the oilsands since 2011 and is ready to prove it in the field.

“I think it is going to be meaningful for us, but I’m happy to say that I think it is going to be meaningful for the market as well,” he says.

Southern Pacific Resource is making plans to hibernate the STP-McKay facility by the end of July 2015.

The company says its hibernation plans are thorough and are intended to enable preservation of the assets for an extended period, if required. With the current low-priced crude market, the property continues to generate negative cash flow and “thus this measure was deemed necessary in order to preserve capital.”

Southern Pacific has experienced difficulty ramping up production to STPMcKay’s nameplate 12,000-bbl/d capacity since start-up in 2012, having yet to exceed monthly average production above 2,500 bbls/d, according to data from the Alberta Energy Regulator.

Meanwhile, Baytex Energy’s Gemini SAGD pilot will be decommissioned due to the current low-oil price environment and a power-plant outage.

Operations commenced over a year ago, and the company says it has captured the key data associated with the pilot’s objectives in that time.

The project’s primary aim was to confirm reservoir production capacity and continuity to support a commercial scale project. Additionally, the pilot provided critical information on facility and well design. To date, the well pair has produced 200,000 barrels of bitumen with an instantaneous steam to oil ratio of 2.3:1.

Production from the well pair peaked at over 1,100 bbls/d and has consistently produced at rates of between 600 and 800 bbls/d. In December 2014, the company filed an application requesting an amendment to its existing approval to allow for a 5,000-bbl/d facility. Following regulatory approval, any subsequent sanctioning decision will be considered in the context of the project economics in a higher commodity price environment, Baytex says.

Southern Pacific’s STP-MacKay SAGD project at start-up in 2012.

JULY / AUGUST 2015 | OILSANDSREVIEW.COM

9

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eyes on the oilsands WHAT PEOPLE ARE SAYING ABOUT THE INDUSTRY IN THE MEDIA AROUND THE WORLD

“The previous [Alberta] government had lost all credibility. I’m optimistic.”

— Todd Hirsch, chief economist with ATB Financial. Bloomberg Business, May 21.

“We think climate change is happening….

We think a broadbased carbon price is the right answer.”

PHOTOS: (CLOCKWISE FROM TOP) TODD HIRSCH; JOEY PODLUBNY; JEFFRUBIN.COM; PCL; HUFFINGTON POST

— Steve Williams, Suncor Energy president and chief executive officer. CBC News, May 23.

“The fundamental issue is the competitive environment [for the oilsands] has changed drastically over the last five years….

It’s not the size that matters. The companies that win are the ones that can deploy capital competitively.”

— Samir Kayande, analyst at ITG Investment Research.

The Globe and Mail, May 17.

“Despite claiming for years that Canada would align with the U.S. on regulating greenhouse gas pollution, the federal government has now set a target that would leave us trailing behind our neighbour if it continues on its current pathway of emissions reductions.”

— Amin Asdollahi, oilsands program director with the Pembina Insitute, addressing the federal government’s new emissions reduction targets. The plan targets 30 per cent reduction below 2005 levels by 2030, but does not include specific actions for the oilsands sector.

National Observer, May 15.

“No oil industry in the world is more vulnerable to plunging oil prices than the oilsands.”

— Jeff Rubin, former chief economist at CIBC World Markets and author of the new book, The carbon bubble: What happens to us when it bursts. Winnipeg Free Press, May 16.

JULY / AUGUST 2015 | OILSANDSREVIEW.COM

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C OV ER STORY

DESPITE A STALL IN GROWTH CAPITAL, PRODUCERS ARE EXPECTED TO SPEND MORE ON MAINTENANCE AND OPERATIONS THROUGH 2017 AS NEW PROJECTS COME ONLINE

By Jim Bentein and Deborah Jaremko

12

OILSANDS REVIEW | JULY / AUGUST 2015

I

n the words of Rich Kruger, chief executive officer of Imperial Oil, there has been a “giant screeching sound” of projects being slowed or deferred as low prices exacerbate the oilsands industry’s market access and social licence challenges.

Kruger was speaking at this year’s PricewaterhouseCoopers Energy Visions event, where he warned about becoming preoccupied with short-term issues while losing sight of long-term goals.

Imperial is, of course, known for its steady hand in capital deployment, even running counter-cyclical with major investments, such as its sanction of the Kearl oilsands mine during the bottom of the Great Recession in

2009. The expansion to that 110,000-bbl/d plant, which the company is currently building, is one of a handful of major projects that is contributing to a shift in the way oilsands producers spend—and, by extension, the opportunity structure for their suppliers.

Producers are recognizing this shift in their business. Chris McInnis, Cenovus Energy’s Christina Lake field development manager, noted at a recent Oilsands Review Speaker Series breakfast that the sustaining costs of a SAGD project will be quite large, even compared to the capital cost of the central processing facility.

“A lot of people are starting to recognize that there is a huge amount of money that is

going to be invested in the sustaining side of our business,” says McInnis, who started in Cenovus’ capital projects group, but is now tasked with applying the cost-saving lessons learned from its manufacturing approach to operations.

A new report from CanOils predicts that even though producers are dramatically reducing the growth capital into the oilsands market, spend will increase in the areas of small and sustaining project capital and maintenance, repair and operations (MRO).

“Despite delays in new project development, this market is expanding,” CanOils analysts write, indicating that about 750,000 bbls/d of new capacity is expected to come

online by 2017. Correspondingly, CanOils predicts that spend on operational efficiency will increase by several billion dollars.

“It is not expected that the renewed focus on per barrel cost reduction will cause a significant decrease to the addressable MRO spend [for suppliers] as production volume growth will outpace any newly achieved cost savings.”

CanOils notes that while producers are expected to spend more in aggregate on small and sustaining capital and MRO, the focus on cost control will be increasingly important.

“Service and supply companies will have to refine their own pricing and cost structures to find ways to maintain margin while

JULY / AUGUST 2015 | OILSANDSREVIEW.COM

13

C OV ER STORY

Does your company see sustaining capital/maintenance projects as a growth opportunity in the oilsands?

79%

21%

YES

stripping out up to 30 per cent of costs as mandated by some producers,” the analysts write. “A number of strategies exist to meaningfully move this needle.”

Scott Sharabura, Calgary-based associate principal with international consulting firm McKinsey & Company, says the company is seeing a growing focus on decreasing spending requirements for oilsands projects.

“There is a very big focus on capital cost reduction now,” he says, adding that focus is also clear for MRO. While there are currently new capital projects continuing, Sharabura says that if lower oil prices prevail, that’s unlikely to be the case beyond 2017.

Meanwhile, producers are taking a “back to the basics” approach to their operations, he says, with moves such as eliminating discretionary work.

Sharabura, a chemical engineer who is a veteran of the oil and gas industry—his first job was at Imperial Oil’s Sarnia refinery in the 1990s—says producers are developing closer relationships with service providers to hone in on cost reduction and efficiency.

“That makes sense because a lot of the technical know-how lies with the service providers. They look to you to be part of the solution.”

John Norcross, vice-president, Canada, with Houston-based consultancy Evolve

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OILSANDS REVIEW | JULY / AUGUST 2015

NO

Partners says the industry—and oilsands operators in particular—need to move away from “boom and bust” mentality.

“They need to design their operations independent of the commodity cost cycle,” say Norcross, who has a degree in industrial sociology from Carleton University, followed by more than 17 years working with senior managers internationally in developing human resources, systems and process capabilities to improve productivity and efficiency.

Norcross says oilsands producers and suppliers can learn from the experience of other industries, pointing to the auto sector, with moves ranging from developing a more efficient supply chain to the use of robotics to drive down costs, as a prime example.

“We [need to] understand how the auto industry has made its supply chain more efficient, otherwise we’ll continue with this boombust cycle.”

There are also examples within the energy industry of operators who have dealt with commodity price volatility by improving their efficiency and cost structure, he says, singling out natural gas–focused companies like Peyto Exploration & Development, which has remained profitable in a low gas price environment.

“They’re used to it,” he says, adding that oilsands operators need to develop sustainable solutions to make their operations cost efficient and productive for the long term.

In Oilsands Review’s 2015 Oilsands Industry Outlook Survey, sponsored by KPMG, respondents were asked whether they viewed sustaining capital and maintenance projects as a growth opportunity. The result was an overwhelming yes.

Sharabura also says there is much to learn about cost control from other industries that have navigated tough competitive environments, such as the mining sector.

One of the problems he is finding is that many of the younger engineers and other managers in the oilsands industry today have seen mostly good times, with the exception of the brief 2008-09 downturn. As a result, they don’t have the same flexibility as older managers.

“Anybody who lived through the 1980s knows how to be a cheapskate,” Sharabura says.

Roger Keglowitsch, senior vice-president of Edmonton-based MRO specialist Melloy, a division of PCL Construction, says that although this could be a good time to deploy capital because of lower supply costs, most oilsands producers are doing only what is absolutely necessary.

Melloy does pipe fabricating and builds modules for oilsands plants. Keglowitsch says that end of the business, plus its shutdown and turnaround-focused divisions, have continued to be busy. But that is unlikely to be the case in the future, especially in its module and fabricating areas.

C OV ER STORY

“We’ll have less to bid on in 2016 and 2017,” he says, adding that, to adjust, Melloy will “err on the side of being lean” with regard to staffing.

Melloy currently employs about 700 people, down from about 1,000 at the same time in spring 2014 during peak shutdown season. Keglowitsch anticipates the fall season will be busy too, although somewhat less so than last year.

The company’s MRO business will be sustained by the fact there are simply many more oilsands mines, thermal projects, upgraders and other related infrastructure in place than ever in the past, he says.

“The maintenance and turnaround work will carry on. That’s the difference from 15 years ago.”

However, Melloy is being asked to play a key role in reducing MRO costs.

“They want the same amount of work done with fewer people,” he says, adding that it’s helping to reduce costs by making turnarounds more repeatable by using the same crews.

The company is also working more closely with operators in the planning phases of shutdowns and turnarounds.

“We have our people there six to 10 months before the turnaround,” Keglowitsch says. “In the past, it was two or three months.”

Another change is that producers have more specific and detailed targets in mind for projects than was the case in the past.

Keglowitsch says operators are also making it clear they want the cost reduction to be more sustainable than in the past.

As Imperial Oil’s Kruger noted at the recent PricewaterhouseCoopers event, it is unclear where oil prices are headed, but Imperial is “looking at this as if we could be in for a sustained period of lower prices, and we’ll be operating and planning our business on that basis.”

To access the CanOils report, Hunting opportunities: Following the producer spend in a bear oilsands market, please visit canoils.com.

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M O D U L E FA B R I C AT I O N

Oilsands producers and contractors lay down the rules for eliminating—or just reducing—change order culture

By Joseph Caouette

S

ix bidders enter. Six bidders leave, all empty-handed.

The project owner did not reject them. Rather, they rejected the project owner, which was looking for a contractor to take on a lump-sum construction package. Despite what seemed like a well-defined scope involving, in the words of one employee at the owner company, “tons and tons of files,” none of the six bidders taking part in the request for proposals felt they had enough information to do the job.

No one wanted to be dragged into a messy process involving a steady stream of change orders.

The owner in question, an oilsands producer that the employee requested not be named, was humbled by the sting of that rejection and reconsidered its entire approach to the project. A cost-reimbursable model was chosen to allow both contractor and owner to better understand the project scope, and it

left open the option to shift over to lump sum at a later date. Lesson learned.

Such candid confessions were one of the highlights of the recent Modular Construction and Prefabrication Summit in Calgary, where representatives from the fabrication and contracting side of the industry aired their grievances with project owners—and vice versa. It could have been a group therapy session for the heavy industrial construction sector. “Hi, my name is Bill, and it has been 58 days since my last change order.”

Fighting project changes was a recurring theme threaded through multiple sessions, and Martin Clutterbuck, manager of fabrication and modularization at Devon Canada, has an idea of just what a system free of incessant changes would look like. Owners finish their design basis memoranda before engineers release a completed issue for construction.

JULY / AUGUST 2015 | OILSANDSREVIEW.COM

17

M O D U L E FA B R I C AT I O N

“If we’re in an hour-long discussion about a construction methodology with everybody blue-skying, we’ll throw a week of engineering at something and then come around for a follow-up meeting. In our view, that’s really part of the bidding process.”

— Mike Hussey, North American regional director, Sarens Group

The builder receives a complete work package before heading into the field. Everyone completes their work and then passes it on to the next group in the chain.

Is Clutterbuck just dreaming? Is it impossible? Unsurprisingly, his audience of hardened industry veterans responds with a resounding, “Yes.” But while it may be unrealistic to expect flawless front-end planning and seamless execution, Clutterbuck believes there are still ways to effectively manage change. He points to the example of a recent Devon project that whittled down 900 contractor requests for information to a mere 10 change orders—worth $1.5 million, or three per cent of the total contract.

“Perhaps if the detailed engineering and scope development had been better, we had the potential to reduce that down even some more,” he says. “I believe there are opportunities out there for us to mitigate the changes and reduce them on our projects.”

He lays down a few basic rules. Structural steel should come after the 60 per cent model review. Be disciplined as an owner and don’t release drawings until the 90 per cent review. Move the electrical work to an earlier point in the process, particularly when modularizing. And others at the conference stress that the operations team should be included during front-end planning. No one wants a late-stage surprise once module production has already begun.

Transport and logistics contractors want to be brought in earlier as well, according to

18

OILSANDS REVIEW | JULY / AUGUST 2015

Gary Trigg, vice-president and general manager of PCL Industrial Management. He recalls a customer that tested its decision to contract overseas suppliers by bringing in a sample module from South Korea. The company shipped the module to Houston and went up through the U.S. to Canada, and in the process learned a great deal about the logistical challenges that lay ahead.

Mike Hussey, North American regional director of logistics provider Sarens Group, echoes Trigg’s call to bring transporters into a project early on, particularly if the design decisions will affect how the modules are shipped and lifted. But early involvement is not a panacea for all problems, he notes.

Given the long lead times on major projects, market assumptions often shift between planning and production. Labour costs can rise and productivity projections can drop.

The wisdom of going offshore for modules can become uncertain if a downturn frees up space in Alberta yards.

The rising international profile of the oilsands also creates new challenges.

Hussey’s company is currently looking at a proposal to move modules through the U.S. to Alberta. However, organized resistance to moving modules has become increasingly common in a number of states over the past six months. Once the Department of Transportation posts information on a module move, the job is now almost guaranteed to meet some form of public opposition.

“That’s the sort of situation where if you’re not retesting those assumptions from the original FEED [front-end engineering and design] study, you get into some real trouble,” he says. “Involve [contractors] early, but continue to test those assumptions at various decision points along the process.”

Questions of financial compensation for the contractor’s time can further complicate the decision to bring them into a project earlier. Trigg suggests bringing in a shortlist of three to five potential bidders at the FEED stage to provide input on the project. Others argue for treating contractors as consultants during these early stages. Hussey expects to offer some advice and input gratis while scoping out potential jobs. That’s just the price of doing business, he argues.

“If we’re in an hour-long discussion about a construction methodology with everybody blue-skying, we’ll throw a week of engineering at something and then come around for a follow-up meeting,” Hussey says. “In our view, that’s really part of the bidding process.”

With the future clouded by uncertain markets and stagnant oil prices, there is precious little blue sky in sight, however. At one session at the summit, an audience member reminds the crowd that owners will always face cost pressures, and upfront engineering remains an easy target when looking for savings.

Driven by a tight schedule, the owner then moves on to construction with little sense of

M O D U L E FA B R I C AT I O N

how those early engineering gaps could lead to large changes later on.

Such are the dangers of a ser viceoriented industry, where the emphasis is on finding someone who can do the job for the fewest hours and lowest cost possible. One participant at the summit draws a distinction between this approach and the solutions-driven model. Rather than treating the contractor as a waiter that must cater to the customer’s whims, no matter how questionable—“Sandwich sans bread? If m’sieur wishes, certainly”—owners should look to these companies as partners trying to solve the same problem. Focus on providing the contractor what it needs to do its job efficiently instead of trying to save costs by rushing the process.

Owners have an obligation to provide well-defined projects, but contractors still have their own role to play in preventing changes and ensuring projects run smoothly, Hussey says. If the service provider has doubts about the project or its own ability to do the work, then it needs to be upfront with the owner. In this industry, the customer is not always right, and a successful contractor doesn’t just land the good jobs—it avoids the bad ones too.

Sometimes that means speaking up, no matter the consequences. Three weeks before the event, Hussey entered a prefeasibility session where he point-blank told a potential client that he thought its preferred route was a mistake. He saw too much risk in their choice, and he made it clear he did not want to bid on the job if they insisted on going down that road.

Perhaps he had talked himself out of a job, he admits. Still, the client was grateful for his candor, and the project may well benefit from the talk, even if Sarens ultimately doesn’t land the contract. Not everyone in the industry is comfortable with that kind of honesty, but Hussey is seeing more of it every day in his dealings. Indeed, the entire summit, with its frank exchanges between owners and contractors, could serve as a model for this type of open dialogue in action.

“The worst service you can provide someone, especially if you’re involved early in the process, is not laying out the risks,” he says. “We need to transfer best practices not only throughout an organization, but across organizations.”

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JULY / AUGUST 2015 | OILSANDSREVIEW.COM

19

Industry welcomes Alberta’s new tailings management framework as the government suspends Directive 074

By Melanie Collison

O

ilsands surface mine operators are welcoming the certainty built into the province’s new tailings management framework, which regulates tailings from generation to deposit to site reclamation.

“We are pleased as an industry to see a policy that covers the entire life cycle of oilsands tailings requirements, including reclamation and financial security,” says Greg Stringham, vicepresident of oilsands and markets with the Canadian Association of Petroleum Producers.

He says that producers appreciate that the framework “causes them to be innovative to make sure they can meet the limits that are coming, as well as improve the efficiency of the processes they have in place right now.”

The Tailings Management Framework for the Mineable 20

OILSANDS REVIEW | JULY / AUGUST 2015

Athabasca Oil Sands, adopted this spring, aims clearly at a finished landscape. It sets timelines and volume targets for both legacy tailings produced since 1967 and new tailings created—at a slower rate—as mines continue operating and grow.

In tackling the life cycle, “our intent is to find the right balance, a rate and a volume operators can handle versus just stockpiling more.

[We want tailings] managed in a way that does not create a long-term liability,” says Andy Ridge, executive director of water policy for Alberta Environment and Sustainable Resource Development (AESRD).

His team spearheaded writing the framework because tailings management is also water management.

Technology will govern the degree of success and cost, he says, but the focus is the environmental outcomes and performance, as well as transparency and added rigour in

reviewing plans and assessing performance. A key piece is water management, and the new framework will adjust the regulatory view.

“Prior to the framework, we said no water can be released into the Athabasca River,” Ridge says.

“We’ve now said that as part of the ultimate removal of tailings, there has to be a plan for the water. Some will stay on the landscape in end pit lakes. Some will be recycled and used in other operations. Some will be treated and released back into the Athabasca. We want to ensure water is used in the most effective way from an environmental and economic perspective.”

The C ouncil of C anadian Academies recently recognized this as an important change in the approach to tailings, although it was unable to fully assess the new framework before publishing its lateMay report, Technological prospects

for reducing the environmental footprint of Canadian oil sands.

“The current policy of zero water discharge and the absence of water treatment standards mean that, even if water recycling rates increase, tailings ponds will continue to exist and grow as bitumen production increases,” reads the report.

“This lack of regulatory criteria for treatment and discharge of process-affected water is considered by the panel a major impediment to both water and tailings management in the region.”

SUSPENDING DIRECTIVE 074 In 2009, the Energy Resources Conservation Board (now Alberta Energy Regulator, AER) introduced Directive 074 to make the point that fine fluid tailings could not mount up indefinitely. It said producers must expand field trials of the most satisfactory technologies

PHOTO: PEMBINA INSTITUTE

W AT E R M A N A G E M E N T

W AT E R M A N A G E M E N T

COSIA’s tailings technology progress According to Greg Stringham, vice-president of oilsands and markets with the Canadian Association of Petroleum Producers, nearly two-thirds of the $1 billion that Canada’s Oil Sands Innovation Alliance (COSIA) has invested so far has focused on tailings treatment.

That’s because there is so much existing research, and the COSIA members have many technologies to share.

IN 2014, TWO PROJECTS WERE COMPLETED: Phase 2 of accelerated dewatering at Syncrude.

Chemical flocculant binds suspended fine clay particles together to release water and settle faster. The resulting denser mixture is spread to dry in sun.

Mature fine tailings (MFT) dynamic flocculation at Shell with Teck Resources and Ledcor Nalco Services.

Filter press technology mechanically squeezes water out of MFT after chemical treatment to keep tailings from sticking to the filter. The resulting clay cake can be strong enough for land reclamation.

TWO PROJECTS WERE CONTINUED: Testing of cross-flow filtration at Natural Resources Canada’s Devon, Alta., oilsands tailings research facility and the University of Alberta. The tailings stream flows through a porous or slotted pipe for filtering and dewatering—the idea is to remove more

and solve the complicated questions of logistics.

The directive focused on reducing fluid tailings volumes and creating trafficable deposits; that is, deposits stable and firm enough to support reclamation.

By 2013, operators were falling short of their commitments. In those four years, 725 million cubic metres of fluid tailings swelled to 925 million cubic metres. However, in the two years since, only another 51 million cubic metres has been added.

“A lot of new technologies have been put in place on a fairly large scale,” Stringham says.

Both AER and AESRD credit Directive 074.

“Because of Directive 074, the technology evolved quite significantly in a very short period of time,” Ridge says.

AER spokeswoman Cara Tobin adds that Directive 074 “encouraged

companies to think about tailings management proactively, as opposed to leaving it to later. They optimized existing technologies and developed new technologies and shared results with each other in COSIA.” Canada’s Oil Sands Innovation Alliance is an umbrella organization within which operators collaborate on technology development. Its work on tailings builds on that of the Oil Sands Tailings Consortium.

Ridge says that the new framework is meant to correct the limitations of Directive 074. “In the past we pushed too hard on technology expectations. We should be pushing industry, but [we should] be realistic.”

In requiring operators to make commitments to specific technologies, “Directive 074 was too prescriptive,” says long-time Natural Resources Canada tailings researcher Randy Mikula, who now

water from tailings before the material reaches settling ponds.

Commercial centrifugation at Shell, working with Syncrude and Newalta. Essentially, spinning speeds release of water from tailings. Syncrude, which is now starting up its commercial centrifuge, contributed technology and pilot study findings. Shell is working on adapting the process to its own operations.

TWO PROJECTS WERE INITIATED: Canadian Natural and six partners engaged the Saskatchewan Research Council to model pipe design for transporting thickened tailings in a laminar flow, i.e. non-turbulent flow of a viscous fluid in layers. Thick treated tailings require significant energy to generate turbulent flow, so operating slurry pipelines in laminar flow could save energy and reduce pipe wear. Canadian Natural used the model for its tailings thickening facilities, which are expected to come online this fall.

Chemically induced micro-agglomeration, conducted by Suncor with Imperial Oil. Imperial research chemists were recently granted a patent for a process to condition tailings with an aluminate and treat volumes with a silicate-containing stream.

Suncor is interested in the technology for treating MFT and is currently conducting laboratory testing.

runs the Edmonton consulting firm Kalium Research. “Now it’s all about the end game and reclamation and reducing the volume of the tailings ponds.”

Mikula says that in the last several years of experience, people have come to realize that producers have complex and unique tailings management positions, so a prescriptive approach is not best.

“Suncor’s pond, for example, is doing extraordinary things on something much weaker than five kPa,” he says. Five kPa is the minimum kilopascal shear strength the regulator requires within a year of depositing treated fine tailings.

SHARING RESPONSIBILITY FOR TAILINGS MANAGEMENT The government aims now to limit tailings accumulation by tightening the rate of creation and setting an expectation for progressive

treatment and reclamation throughout a project’s life.

The clock starts when any specific mine stops production. The landscape must be ready for reclamation within 10 years.

“From creation to treatment to reclamation is similar to how we view our tailings management,” Suncor spokeswoman Sneh Seetal recently told Oilsands Review. “The tailings management framework is flexible but quite stringent. We will have to draft a plan and steward to that plan.”

The framework will push investment in technologies, identify thresholds when companies must take action and strengthen reporting systems “so we know sooner rather than later if things aren’t working,” Ridge says.

Companies must post additional financial security through the Mine Financial Security

JULY / AUGUST 2015 | OILSANDSREVIEW.COM

21

W AT E R M A N A G E M E N T

Program to backstop potential remediation delays.

“Albertans have assurance they’re not going to be left with the cost of cleanup,” Ridge says.

The framework says outright that industry and government share responsibility for tailings management.

The AER is incorporating AESRD and stakeholder input as it grapples with the formidable task of turning policy into regulations.

It must decide the critically important limits, triggers and thresholds that indicate whether a company is on track, and determine enforcement protocols— and quickly.

“Our intention is to be as open and transparent as possible. We’ll make [the information] available to as many people as possible,” AER’s Tobin says, perhaps by posting a somewhat simplified version online.

The framework is different enough from Directive 074 that the agency has temporarily suspended

“Now it’s all about the end game and reclamation and reducing the volume of the tailings ponds.”

— Randy Mikula, Kalium Research

reporting, but tailings management must continue.

“We expect to have draft requirements ready for stakeholder feedback for this fall,” Tobin says. The final version is targeted for spring 2016, but “this will be a continuing evolution. We’ll learn along the way and continue to develop the requirements.”

Stringham says the framework’s individualized approach works for industry. “It addresses tailings on a project-by-project basis, where each has a specific plan and accountability.”

The most advanced new technologies are Syncrude Canada’s centrifuge system, and the multiple thin layers and atmospheric

fines drying technologies being deployed by Suncor Energy and Shell Canada.

Syncrude expects to be operating this year with a $1.9-billion full-scale plant outfitted with 18 centrifuges, winterized and working year-round.

“When companies start to submit their plans for review and approval, what exactly everybody is going to do is going to be interesting,” Mikula says.

“Science is now optimizing and improving the processes in use.

You can guarantee some evolutionary improvement, but while you’re doing that science, there’s always the hope something revolutionary will come out and make everything easy and cheap.”

To read the Pembina Institute’s perspective on Alberta’s new tailings management framework, read the Transition column on page 35.

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22

OILSANDS REVIEW | JULY / AUGUST 2015

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This is the last article in a four-part series about renewed development momentum in Alberta’s Industrial Heartland.

CENTRAL AND DIVERSIFIED Neil Shelly, executive director of Alberta’s Industrial Heartland Association (AIHA) and Wayne Woldanski, reeve of Lamont County and AIHA board chair.

Alberta’s Industrial Heartland Association leaders focus on a future that doesn’t depend on oilsands upgrading

By Melanie Collison

lberta’s Industrial Heartland region has come a long way since plans for Upgrader Alley toppled like dominoes at the end of the last decade as the Great Recession put the final nail in a market already moving away from wide-scale bitumen upgrading in Alberta.

But leaders of Alberta’s Industrial Heartland Association (AIHA) knew that the economic value of the region remained unchanged. Now, they are seeing new momentum towards their planned massive eco-industrial complex in the centre of the province.

“We went through an ebb time, but we have new opportunities now,” says AIHA executive director Neil Shelly. Oilsands Review spoke with Shelly and board chair Wayne Woldanski about what lies ahead for the region.

Q: What opportunities are you working on?

PHOTO: JOEY PODLUBNY

A: The new opportunities now are in natural gas processing and petrochemicals related to shale gas. We have low natural gas prices and a significant resource with shale gas development.

Our research confirms investments in this area can be attractive and globally competitive as a base for ethane-based petrochemical operation.

We think there’s huge potential. We’ve had around 15 major companies look at our area this last year, looking at doing something petrochemical-based. It takes a year or two to make their investigation, then three to five years to build a project, so it could be five to eight years before we actually see anything being produced.

We’re seeing a doubling or tripling of the three fractionation plants within the Fort Saskatchewan–Industrial Heartland region.

Keyera is investing $225 million in a fractionation expansion, plus $200 million to add pipeline connections and underground storage caverns to hold another four million barrels of NGL [natural gas liquids] mix feedstock and specification NGLs.

Plains Midstream Canada is reworking its truck-loading infrastructure and building rail facilities, adding caverns and connectivity, and has more expansion on the drawing board.

Pembina Pipelines is putting $350 million into a large-scale condensate and diluent terminal to add to its existing diluent handling facilities. A second phase will add more rail capability and underground cavern storage.

Q: How is the eco-industrial aspect of the region—in which plants share resources and infrastructure and use their neighbours’ byproducts as feedstock—working out so far?

A:

We promote the eco-industrial side and the carbon-capture projects happening in the area…. These provide opportunities to reduce the carbon footprint of projects that may go ahead in the future. We’re promoting environmental leadership. The province has put in significant investment and eventually, down the road, they’ll reach their potential. Companies like knowing that their feedstocks are available locally and they can sell by-products to neighbours.

Williams Energy, at its fractionation plant, wants to turn upgrader off-gases into propylene. Companies had been using those gases as fuel, but its value as a petrochemical feedstock is much, much greater. It’s making a $2-billion-plus investment. Its propane dehydrogenation produces hydrogen as a side product and there’s lots of demand for it.

We’re hoping to hear an announcement shortly, whether that’s in one month or six months. They’ve purchased land and have done a lot of FEED [front-end engineering and design] and have their permits. The new plant would be 500 metres away across the river, and they already have access to pipelines under the river.

Q: What about other developments?

A: Transportation and infrastructure in the area are key to all the logistics, and we’re constantly advocating for improvements. Right now, we’re looking for a heavy-haul bridge just south of Fort Saskatchewan—a new river crossing that has the capacity to take large vessels.

Q: What’s your most important message?

A: We continue to advocate to the province that we need a strategy to add value to our resources to stabilize revenues and minimize spikes in our revenue stream. We’re looking for key government policy decisions. That goes back to the early 1970s when Premier Peter Lougheed got things off the ground within the Fort McMurray area and for the petrochemical industry.

JULY / AUGUST 2015 | OILSANDSREVIEW.COM

23

CURRENT PROJECT

CAPACITY

START-UP

REGULATORY STATUS

Shell Albian Sands Jackpine

Updated: May 2015

Extended planned maintenance during spring/summer 2015.

project status Sourced from Alberta regulators and corporate disclosures.

For changes and updates, please contact Deborah Jaremko at djaremko@junewarren-nickles.com.

Phase 1A

100,000

2010

OP

Phase 1B

100,000

TBD

Approved

Expansion

100,000

TBD

Muskeg River

Marathon says that production increased by approximately 35 percent in the first quarter, primarily as a result of higher reliability compared to the first quarter when nine days of planned mine maintenance occurred. A planned turnaround is scheduled for late spring/early summer.

Commercial

155,000

2002

Expansion & Debottlenecking

115,000

TBD

Pierre River

Disclaimer: Oilsands Review accepts no liability for errors or inaccuracies in the information provided in this report.

South Athabasca region

Phase 1

100,000

TBD

Cancelled

Phase 2

100,000

TBD

Cancelled

Base Operations

Saskatchewan region Industrial Heartland region

Millennium Mine

New information this month

Steepbank Debottlenecking Phase 3 Millennium Debottlenecking North Steepbank Extension

294,000

1967

OP

4,000

2007

OP

23,000

2008

OP

180,000

2012

OP

Announced; regulatory application pending

•

Regulatory application has been filed

Suncor says the project is on schedule and on budget, and the company is starting to see an increase in labour supply and productivity. Construction activities are ramping up and detailed engineering is moving towards completion.

Regulatory approval in place

UC

Under construction

OP

Operating

Fort Hills

Phase 1 Debottleneck

HOLD

On hold; timing uncertain

SUSP

Operations suspended

CAN

Updated: May 2015

Suncor reported record synthetic crude oil production in the first quarter due to strong upgrader reliability. Production is expected to decrease in the second quarter due to planned coker maintenance.

Peace River region

APPL

Approved Updated: Mar 2015

Suncor Energy Inc.

Cold Lake region

Approved

OP

Shell has withdrawn its application for the Pierre River project, saying it wants to focus on its existing oilsands operations. The company says it will continue to hold the Pierre River leases and may re-apply in the future.

North Athabasca region

ANN

Approved Updated: May 2015

Updated: Jun 2015

160,000 20,000

2017 TBD

Voyageur South

UC Approved Updated: May 2012

Suncor considers Voyageur South to be a longer-term project and has not confirmed a start-up date.

Project cancelled

Phase 1

120,000

TBD

APPL

Syncrude Canada Ltd. Mildred Lake/Aurora

navigator.oilsandsreview.com For more detailed project data, visit oilsandsreview.com.

To explore oilsands projects using our interactive web tool, visit the Canadian Oilsands Navigator.

CURRENT PROJECT

CAPACITY

START-UP

REGULATORY STATUS

Canadian Natural Resources Limited Horizon

Updated: Jun 2015

Canadian Natural says that its 2015 maintenance turnaround has been accelerated to June from the fall. Overall, the company says its Phase 2/3 expansion is approximately 60 per cent physically complete.

Phase 1

135,000

2008

OP

5,000

2014

OP

Phase 2A

12,000

2014

OP

Phase 2B

45,000

2016

UC

Phase 3

80,000

2017

UC

Reliability - Tranche 2

Imperial Oil Limited •

290,700

1978

OP

Stage 3 Expansion

116,300

2006

OP

TBD

TBD

OP

Aurora SouthTrain 1

100,000

TBD

Approved

Aurora SouthTrain 2

100,000

TBD

Approved

Mildred Lake Mine Extension (MLX)

184,000

2023

APPL

Centrifuge Tailings Management

Teck Resources Limited Updated: Apr 2015

Teck says that the regulatory review process for the Frontier project is expected to continue through 2015, making 2016 the earliest an approval decision and receipt of required permits is expected.

Phase 1

74,600

2021

APPL

Phase 2

84,000

2024

APPL

Phase 3

79,300

2027

APPL

Phase 4 Equinox

39,400

2030

APPL

Total E&P Canada Ltd. Joslyn North Mine

Updated: Mar 2015

Total has withdrawn the regulatory applications for the Joslyn North Mine.

Phase 1

100,000

TBD

HOLD

NORTH ATHABASCA REGION — IN SITU

Kearl

Updated: Jun 2015

Imperial says that production averaged 95,000 bbls/d in the first quarter, and that all three mine trains have been simultaneously operated at capacity. The company started up its cogeneration unit and synchronized to the Alberta grid in the first quarter. Commissioning of the Kearl expansion project continues to progress, and start-up is expected by mid-year.

24

Base Mine Stage 1 & 2 Expansion

Frontier

NORTH ATHABASCA REGION — MINING •

Updated: May 2015

Syncrude has filed the regulatory application for the MLX project. During 2015, Syncrude is focusing on cost reduction to remain profitable during the low oil price environment.

Athabasca Oil Corporation Birch

Updated: Feb 2015

Athabasca lists Birch as one of its long-term assets.

Phase 1

12,000

TBD

ANN

Phase 1

110,000

2013

OP

Phase 2

110,000

2015

OP

Phase 3

80,000

2020

Approved

Phase 1 Demonstration

6,000

TBD

Approved

Phase 4 Debottlenecking

45,000

TBD

Approved

Phase 2 Demonstration

6,000

TBD

APPL

OILSANDS REVIEW | JULY / AUGUST 2015

Dover West Carbonates (Leduc)

Updated: Mar 2015

Athabasca lists Dover West as one of its long-term assets.

CURRENT PROJECT

CAPACITY

START-UP

Dover West Sands & Clastics

REGULATORY STATUS

Updated: Feb 2015

CURRENT PROJECT

Saleski

12,000

TBD

APPL

Phase 2

35,000

2019

ANN

Carbonate Pilot

Phase 3

35,000

2020

ANN

Sunrise

Phase 4

35,000

2022

ANN

Phase 5

35,000

2024

ANN

Terre de Grace

Updated: Apr 2014 TBD

Approved

Brion Energy Corporation Dover Dover Experimental Pilot

•

Updated: Sep 2014 2,000

2017

Approved

Dover North Phase 1

50,000

TBD

Approved

Dover North Phase 2

50,000

TBD

Approved

Dover South Phase 3

50,000

2021

Approved

Dover South Phase 4

50,000

2023

Approved

Dover South Phase 5

50,000

2025

Approved

Mackay River

Updated: Jun 2015

A video of the lid of the skim tank being placed at MacKay River can be viewed at https://goo.gl/P4rM06.

Phase 1

35,000

2015

UC

Phase 2

40,000

TBD

Approved

Phase 3

40,000

2020

Approved

Phase 4

35,000

2022

Approved

Canadian Natural Resources Limited Birch Mountain

Updated: Dec 2013

Canadian Natural says Birch is in the planning stages.

Phase 1

60,000

2019

ANN

Phase 2

60,000

2023

ANN

Cenovus Energy Inc. East McMurray

Updated: Dec 2013 30,000

TBD

Steepbank

ANN Updated: Dec 2013

Cenovus says this project remains part of its portfolio of long-term development opportunities.

Phase 1

TBD

APPL Updated: May 2015

Phase 1A

30,000

2015

OP

Phase 1B

30,000

2015

UC

Phase 2A

35,000

TBD

HOLD

Phase 2B

35,000

TBD

Approved

Future Phases

70,000

TBD

Approved

Imperial Oil Limited Aspen

Updated: Feb 2014

Alberta has issued the final terms of reference for Imperial’s Aspen project.

Phase 1

45,000

2020

APPL

Phase 2

45,000

TBD

APPL

Phase 3

45,000

TBD

APPL

Ivanhoe Energy Inc. •

Tamarack

Updated: Jun 2015

Ivanhoe has announced that despite considerable efforts by the company, its trustee and major creditors, the parties have been unable to reach a viable restructuring proposal under the Bankruptcy and Insolvency Act. The company was deemed bankrupt as of 11:59 p.m.

MDT on June 1.

Phase 1

20,000

TBD

APPL

Phase 2

20,000

TBD

APPL

Koch Exploration Canada Corporation Dunkirk

Updated: May 2015

Koch has filed the regulatory application for the proposed Dunkirk SAGD project.

Commercial Demonstration

2,000

2017

APPL

Phase 1

30,000

2018

ANN

Phase 2

30,000

TBD

ANN

Marathon Oil Corporation

Cenovus says this project remains part of its portfolio of long-term development opportunities.

Phase 1

3,000

Husky says it achieved first production from the Sunrise SAGD project in mid-March.The company says that production will be ramped up gradually to achieve optimum results, with volumes currently between 2,500 and 3,000 bbls/d. Husky is now using a custom mobile drilling rig to drill sustaining pads.

BP says that ongoing appraisal activities continue.

10,000

Updated: May 2013

Husky filed the regulatory application for its Saleski pilot in early May 2013.

Phase 1

BP p.l.c.

REGULATORY STATUS

START-UP

Husky Energy Inc.

Athabasca lists Dover West as one of its long-term assets.

Pilot

CAPACITY

30,000

TBD

Telephone Lake

ANN Updated: May 2015

Cenovus will significantly reduce spending at its emerging oilsands assets, including Telephone Lake, in 2015. The company has deferred planned development at Telephone Lake to preserve cash.

Phase A

45,000

TBD

HOLD

Phase B

45,000

TBD

Approved

Birchwood

Updated: May 2015

Marathon had anticipated receiving regulatory approval for the Birchwood project by the end of 2014. Upon receiving this approval, the company will further evaluate its development plans.

Demonstration

12,000

TBD

1,720

TBD

APPL

Oak Point Energy Ltd. Lewis Pilot

Updated: Jun 2014 Approved

Prosper Petroleum Ltd. Rigel

Updated: Mar 2015

Prosper Petroleum filed its regulatory application for the Rigel SAGD project in November 2013. Regulatory approval is expected in second half of 2015.

Phase 1

10,000

2017

APPL

SilverWillow Energy Corporation

Grizzly Oil Sands Ulc Thickwood

Updated: Feb 2014

The Alberta Energy Regulator says it will defer decisions on applications for in situ oilsands projects in the new shallow thermal area of the Athabasca region until it has developed formal regulatory requirements. Grizzly Thickwood is one of five impacted projects.

Phase 1

6,000

TBD

APPL

Phase 2

6,000

TBD

APPL

Audet

Updated: May 2015

Until the Alberta Energy Regulator develops and implements its new regulatory requirements, SilverWillow can provide no guarantee that it will be able to meet them or issue a revised project schedule. SilverWillow is optimistic that new regulations pertaining to shallow SAGD development would be established in 2015, however, with the change in government at the provincial level in Alberta the timing of such regulatory changes is less certain.

Pilot

12,000

2018

APPL

PROVEN TECHNOLOGY PROVEN INNOVATION Crude Oil Treatment, Produced Water Deoiling & Gas Processing: including FWKOs Separators, Treaters, Induced Gas Flotation, Oil Removal Filters, Gas Dehydration (TEG & Mole Sieve), Sweetening Plants.

Fjords Processing Canada Inc.

Life cycle services including preventative maintenance, 24/7 parts/service support, brownfield equipment testing & optimization, operator training, start-up & commissioning.

Formerly known as Kvaerner Process Systems & Aker Process Systems — providing equipment since 1976

P: 403.640.4230 www.fjordsprocessing.com

JULY / AUGUST 2015 | OILSANDSREVIEW.COM

25

P R O J E C T S TAT U S

CURRENT PROJECT

CAPACITY

START-UP

REGULATORY STATUS

Southern Pacific Resource Corp.

•

STP-McKay

Updated: May 2015

Southern Pacific and certain of its subsidiaries have obtained creditor protection under the Companies’ Creditors Arrangement Act. The STP-McKay is being suspended to preserve capital until oil prices recover.

Phase 1

CURRENT PROJECT

12,000

2012

SUSP

Suncor Energy Inc. Dover 2014

Firebag

OP Updated: May 2015

Suncor says that it achieved record production at Firebag during the first quarter, with volumes reaching 188,700 bbls/d.

30,000

TBD

APPL

Phase 3

30,000

TBD

APPL

Gregoire Lake

Updated: Dec 2013

Phase 1

60,000

TBD

Phase 2

60,000

TBD

Grouse

ANN ANN Updated: Mar 2015

The Environmental Impact Assessment reportfor the Grouse project was deemed complete March 6, 2015. The review took 148 weeks.

Commercial •

40,000

2020

Kirby

APPL Updated: Jun 2015

35,000

2004

OP

Stage 2

35,000

2006

OP

Cogeneration and Expansion

25,000

2007

OP

Stage 3

42,500

2011

OP

KS1 - Kirby South

40,000

2013

OP

Stage 4

42,500

2012

OP

KN1 - Kirby North

40,000

TBD

HOLD

Stage 5

62,500

TBD

Approved

KN2 - Kirby North

60,000

2022

Approved

Stage 6

62,500

TBD

Approved

Stage 3-6 Debottlenecking

23,000

TBD

40,000

TBD

Phase 2

40,000

TBD

MacKay River

Cavalier Energy Inc. Hoole

APPL Updated: Aug 2013

Phase 1

The company says it will defer spending on Kirby North Phase 1 until oil prices improve. Production at Kirby South was reduced in late May and early June to 12,000 bbls/d due to forest fires in the Cold Lake region.

ANN ANN

Phase 1 Debottleneck MR2

Updated: May 2015

Regulatory approval for the first phase of the Hoole project was granted in June 2014. Development of this phase is dependent upon Cavalier Energy securing financing and sanctioning by its board of directors. In July 2014, Cavalier acquired approximately 23 net sections of undeveloped land contiguous with its Hoole lands for $20 million.

Updated: Jun 2015

Suncor says that spending is currently focused on ongoing wellpad development that is expected to maintain existing production levels.

Phase 1

10,000

TBD

Approved

Phase 2A

35,000

TBD

ANN

Phase 2B

35,000

TBD

ANN

33,000

2002

OP

Cenovus Energy Inc.

5,000

2014

OP

•

TBD

HOLD

The optimization project for Phases C, D and E is expected to come on stream in late 2015, and Phase F is expected to come on stream in the second half of 2016. Phases G and H have been deferred to preserve cash.

20,000

Sunshine Oilsands Ltd. Legend Lake

Updated: May 2015

Awaiting project sanctioning.

Phase A1

10,000

TBD

APPL

Phase A2

30,000

TBD

ANN

Phase B1

30,000

TBD

ANN

Phase B2

30,000

TBD

ANN

Thickwood

Updated: May 2015

Awaiting project sanctioning.

•

Updated: Jun 2015

Phase 2

Stage 1

Lewis

•

Blackrod (continued)

REGULATORY STATUS

Canadian Natural says Gregoire Lake is in the planning stages.

Updated: Mar 2015 500

START-UP

Canadian Natural Resources Limited

N-Solv Corporation says its pilot plant produced its 40,000th barrel of oil in early 2015.

Demonstration Plant

CAPACITY

Phase A1

10,000

TBD

Approved

Phase A2

30,000

TBD

ANN

Phase B

30,000

2021

West Ells

ANN Updated: Jun 2015

Sunshine Oilsands says it is postponing commissioning and start-up to improve productivity and reduce costs. First steam is now expected in late June instead of during the first quarter.

The company says it continues to look for opportunities for joint ventures to reduce capital commitments and to accelerate increased production.

•

Christina Lake

Updated: Jun 2015

Phase 1A

10,000

2002

OP

Phase 1B

8,800

2008

OP

Phase C

40,000

2011

OP

Phase D

40,000

2012

OP

Phase E

40,000

2013

OP

Optimization (Phases C,D,E)

22,000

2015

UC

Phase F

50,000

2016

UC

Phase G

50,000

TBD

HOLD

Phase H

50,000

TBD

Foster Creek

APPL Updated: Jun 2015

Phase G is expected to be onstream in the first half of 2016. Phase H has been deferred until oil prices improve. Production was temporarily shut-in and personnel evacuated in late May due to forest fires in the Cold Lake region.

Phase A Phase B Debottlenecking

24,000

2001

OP

6,000

2003

OP

Phase A1

5,000

2015

UC

Phase C Stage 1

10,000

2005

OP

Phase A2

5,000

TBD

Approved

Phase C Stage 2

20,000

2007

OP

Phase A3

30,000

TBD

ANN

Phase D

30,000

2009

OP

Phase B

20,000

TBD

ANN

Phase E

30,000

2009

OP

Phase C1

30,000

TBD

ANN

Phase F

30,000

2014

OP

Phase C2

30,000

TBD

ANN

Phase G

30,000

2016

UC

SOUTH ATHABASCA REGION — IN SITU

Phase H

30,000

2017

HOLD

Athabasca Oil Corporation

Future Optimization (Phases F,G,H)

35,000

TBD

ANN

Phase J

50,000

TBD

Approved

Future Optimization

15,000

TBD

•

Hangingstone

Updated: Jun 2015

On March 23, 2015, Athabasca commenced steaming the first three well pairs, and 15 well pairs were steaming by mid-April. First production from Phase 1 is expected to be achieved in the third quarter of 2015. Final costs for Phase 1 are expected to fall between $740 million and $750 million.

HS-1 HS-2A Debottlenecking (1 and 2) HS-2B Expansion HS-3

12,000

2015

OP

8,000

2017

APPL

32,000

2019

APPL

30,000

2021

APPL

BlackPearl Resources Inc. •

Blackrod

Updated: Jun 2015

BlackPearl reports that production is expected to ramp-up to peak rates in 2015. During the first quarter of 2015, the pilot wells produced an average of 406 bbls/d of bitumen.

Pilot Phase 1

26

OILSANDS REVIEW | JULY / AUGUST 2015

800 20,000

Grand Rapids

ANN Updated: May 2015

Cenovus says it will reduce spending at its emerging oilsands assets in 2015, including Grand Rapids. The company does plan to drill a third well pair at the operating pilot in the first quarter, and says data from these well pairs will help determine the future pace of its Grand Rapids development.

Pelican Lake Pilot

2011

OP

Pelican Upper Grand Rapids Phase A

10,000

600

TBD

HOLD

Pelican Upper Grand Rapids Phase B

32,000

TBD

Approved

Pelican Upper Grand Rapids Phase C

29,000

TBD

Approved

Pelican Upper Grand Rapids Phase D

29,000

TBD

Approved

Pelican Upper Grand Rapids Phase E

32,000

TBD

Approved

2011

OP

Pelican Upper Grand Rapids Phase F

29,000

TBD

Approved

TBD

APPL

Pelican Upper Grand Rapids Phase G

19,000

TBD

Approved

P R O J E C T S TAT U S

CURRENT PROJECT

CAPACITY

START-UP

Narrows Lake

REGULATORY STATUS

Updated: May 2015

Cenovus has suspended new construction spending on Phase A until crude oil prices recover.

Phase A

45,000

TBD

HOLD

Phase B

45,000

TBD

Approved

Phase C

40,000

TBD

West Kirby

An innovative partner with an award-winning commitment to sustainable solutions

Approved Updated: Dec 2013

Cenovus says this project remains part of its portfolio of long-term development opportunities.

Phase 1

30,000

TBD

Winefred Lake

ANN Updated: Dec 2013

Cenovus says this project remains part of its portfolio of long-term development opportunities.

Phase 1

30,000

TBD

• Engineering • Environmental • Pipeline construction • Permitting • Detailed design

ANN

CNOOC Limited Long Lake

Updated: Apr 2015

An application was filed in early March to amend production capacity at Kinosis 1B to 37,500 bbls/d. Plans for the remaining 12,500 bbls/d (of the 70,000 bbls/d approved) have not been disclosed. Five week shutdown scheduled for the Long Lake Upgrader starting June 1.

Phase 1

72,000

2008

OP

Kinosis (K1A)

20,000

2014

OP

Kinosis (K1B)

37,500

TBD

Approved

Connacher Oil and Gas Limited •

Great Divide

Updated: Jun 2015

In the first quarter of 2015, production increased 12 per cent over the same period in 2014.

Connacher has decided to delay completions of the SAGD+ process commercial project at Algar and the mini steam expansion at Pod One due to depressed commodity prices and liquidity constraints. Connacher has completed its restructuring process. Turnaround planned for the third quarter of 2015.

Pod One

10,000

2007

OP

Algar

10,000

2010

OP

Expansion 1A

12,000

TBD

Approved

Expansion 1B

12,000

TBD

Approved

+1 (626) 351-4664 | oilandgas@tetratech.com | tetratech.com/oilandgas

ConocoPhillips Canada Limited •

Surmont

Updated: Jun 2015

ConocoPhillips has announced that first steam was achieved at Surmont 2 on May 29. Production is expected to ramp up through 2017.

Pilot

1,200

1997

OP

Phase 1

30,000

2007

OP

Phase 2

118,000

2015

OP

Phase 2 Debottlenecking

57,000

TBD

APPL

Phase 3 - Tranche 1

45,000

2020

APPL

Phase 3 - Tranche 2

45,000

2021

APPL

Phase 3 - Tranche 3

45,000

2023

APPL

Devon Canada Corporation •

Jackfish

Updated: Jun 2015

Devon says that beginning in June, Jackfish 1 will have a 21-day maintenance shutdown.

Phase 1

35,000

2007

OP

Phase 2

35,000

2011

OP

Phase 3

35,000

2014

Jackfish East Expansion •

OP

2015 EXPORT CHAMPIONS

Now is your chance to GET RECOGNIZED. Apply for an award in one of the following categories:

Updated: Sep 2012 20,000

2018

Pike

ANN Updated: Jun 2015

Devon has applied to amend total capacity of the Pike project to 70,000 bbls/d from 105,000 bbls/d, using 52 well pads and 12 once-through steam generators. FEED is expected to be completed in 2015 as well as a cost structure.

1A

35,000

2019

Approved

1B

35,000

2020

Approved

1C

35,000

TBD

Cancelled

Grizzly Oil Sands Ulc •

Paying tribute to the success and innovation of Alberta’s export companies.

Algar Lake

Updated: Jun 2015

Grizzly has suspended operations at Algart due to low commodity prices.

Phase 1

6,000

2014

Phase 2

6,000

TBD

May River

SUSP Approved

INDIVIDUAL AWARDS:

Exporter of the Year Emerging Exporter

Leadership International Business Studies

SECTOR AWARDS:

Manufacturing Oil and Gas Service/Supply Clean Technology Consumer Products

Agriculture, Food/ Beverage Professional Services Advanced Technology and Innovation

Updated: May 2015

Grizzly responded to a third round of supplemental information requests regarding its May River application in early March, Regulatory approved is expected in 2015.

Phase 1

6,000

2016

APPL

Phase 2

6,000

TBD

APPL

Don’t forget to apply for your award at

ALBERTAEXPORTAWARDS.COM JULY / AUGUST 2015 | OILSANDSREVIEW.COM

27

P R O J E C T S TAT U S

CURRENT PROJECT

CAPACITY

START-UP

REGULATORY STATUS

BlackGold

REGULATORY STATUS

Updated: May 2015

Statoil temporarily evaucated 150 workers from the Leismer project in late May due to forest fires in the area.

Phase 1

10,000

2015

HOLD

Demonstration

10,000

2010

OP

Phase 2

20,000

TBD

Approved

Commercial

10,000

2011

OP

Expansion

20,000

TBD

Approved

Northwest

20,000

TBD

Disclosed

40,000

TBD

Japan Canada Oil Sands Limited Hangingstone

Updated: May 2015

The Hangingstone expansion will receive its diluent from Inter Pipeline’s Polaris pipeline.

Additionally, Aquatech has been awarded a contract to provide its evaporator technology for OSTG blowdown treatment. First production is expected in 2016.

Expansion

20,000

2016

UC

11,000

1999

OP

Suncor Energy Inc. Chard Phase 1

Pilot Koch Exploration Canada Corporation Muskwa

Updated: Jun 2014

Regulatory approval granted in June 2014.

Pilot

Phase 1

20,000

2020

Approved

Phase 2

30,000

2022

Approved

Phase 3

30,000

TBD

Approved

Wildwood 10,000

TBD

Approved Updated: Mar 2015

Laricina has suspended operations at the Germain SAGD project in order to reduce capital and operating costs as it continues its financial and strategic alternatives.

5,000

2013

SUSP

Updated: May 2015

Surmont is still raising funds to develop the Wildwood project.

Phase 1

Germain

ANN Updated: Sep 2014

Surmont Energy Ltd.

Laricina Energy Ltd.

Phase 1 CDP

Updated: Nov 2012

Meadow Creek East

Hangingstone Pilot

12,000

TBD

APPL

Value Creation Inc. Advanced TriStar

Updated: Mar 2015

The Alberta Energy Regulator says it will defer decisions on applications for in situ oilsands projects in the new shallow thermal area of the Athabasca region until it has developed formal regulatory requirements. Advanced TriStar is one of five impacted projects.

Phase 2

30,000

TBD

APPL

Phase 3

60,000

TBD

APPL

ATS-1

15,000

TBD

APPL

Phase 4

60,000

TBD

APPL

ATS-2

30,000

TBD

APPL

ATS-3

30,000

TBD

Saleski

Updated: Mar 2015

Laricina says that while the Saleski pilot continues to operate, it has suspended development activities on future phases as the company and its partner continue to evaluate available financing alternatives and opportunities within a minimized capital spending program.

Experimental Pilot

1,800

DOEx (Demonstration of Excellence)

APPL Updated: May 2014

Value Creation has filed an amendment to its regulatory approval to increase production capacity from 1,000 to 6,000 bbls/d.

2011

OP

Phase 1

10,700

TBD

HOLD

Phase 2

30,000

TBD

HOLD

Baytex Energy Corp.

Phase 3

60,000

TBD

ANN

•

Phase 4

60,000

2023

ANN

Phase 5

60,000

2026

ANN

Phase 6

60,000

TBD

ANN

Baytex has made the decision to decomission the Gemini SAGD pilot due to low oil pricing.

The company says that since operations started last year the pilot has successfullly captured the key data associated with its objectives. The company’s primary objective was to confirm reservoir production capacity to support a commercial scale project. Following regulatory approval for the commercial project, any subsequent sanctioning decision will be considered in the context of the project economics in a higher commodity price environment.

MEG Energy Corporation Christina Lake

Updated: Jun 2015

Despite significantly cutting its capital budget, MEG continues to target a production increase to up to 82,000 bbls/d from the Christina Lake project in 2015. The company is considering a series of brownfield expansions of Phase 2B. Non-essential staff were evacuated from the Christina Lake project due to forest fires in the region in late May, with MEG also temporarily suspending operations, including a planned turnaround.

Phase 1 Pilot

3,000

2008

OP

Phase 2A

22,000

2009

OP

Phase 2B

35,000

2013

OP

Phase 3A

50,000

TBD

Approved

Phase 3B

50,000

2018

Approved

Phase 3C

50,000

2020

Surmont

Approved Updated: May 2015

The Environmental Assessment Director has deemed the Environmental Impact Assessment report complete for MEG Energy Corp.’s Surmont Project.

Phase 1

40,000

TBD

APPL

Phase 2

40,000

TBD

APPL

Phase 3

40,000

TBD

APPL

OSUM Oil Sands Corp.

Sepiko Kesik

Updated: Mar 2015

Osum says it anticipates regulatory approval for Sepiko Kesik in 2015. Environmental Impact Assessment report has been deemed complete, the review took 91 weeks.

Phase 1

30,000

2018

APPL

Phase 2

30,000

2020

APPL

PTT Exploration and Production Mariana - Thornbury Phase 1

Updated: Feb 2015 40,000

TBD

Approved

Renergy Petroleum (Canada) Co., Ltd. Muskwa

Updated: Mar 2015

Renergy Petroleum received regulatory approval in January.

Muskwa Experimental Pilot

28

START-UP

Leismer

Updated: Jun 2015

Harvest says that production at Phase 1 will be delayed until oil prices recover. Phase 2 project costing is underway.

•

CAPACITY

Statoil

Harvest Operations Corp.

•

CURRENT PROJECT

OILSANDS REVIEW | JULY / AUGUST 2015

TBD

2015

Approved

Pilot

6,000

2018

APPL

COLD LAKE REGION — IN SITU Gemini

Updated: Jun 2015

Pilot

1,200

2014

SUSP

Commercial

5,000

2017

Approved

Birchwood Resources Inc. Sage

Updated: Mar 2015

Birchwood has until Sept. 30, 2015 to submit a response to supplemental information requests related to the Sage regulatory application.

Pilot

5,000

TBD

APPL

Canadian Natural Resources Limited •

Primrose & Wolf Lake

Updated: Jun 2015

Relating to the four sites of surface release discovered in May and June 2013, Canadian Natural says it has full containment of each site and has fully cleaned up all of the flow to these sites. The company has completed the groundwater drilling program on the land sites of the seepages to surface and has confirmed that there is no ongoing contamination of the aquifer away from the sites. The causes of the release have been identified. and a final report is being prepared. A steamflood at Primrose East is expected to add 13,000–15,000 bbls/d by the end of 2015. Candian Natural evacuated 250 workers from its Primrose operations due to forest fires in the Cold Lake region in late May. Wolf Lake

13,000

1985

OP

Primrose South

45,000

1985

OP

Primrose North

30,000

2006

OP

Primrose East

32,000

2008

OP

Devon Canada Corporation Walleye

Updated: Mar 2015

Devon says the Walleye project is currently on hold.

Phase 1

9,000

TBD

10,000

TBD

APPL

Husky Energy Inc. Caribou Demonstration

Updated: Nov 2010

Tucker

Approved Updated: Mar 2015

Maintenance turnaround planned for the third quarter of 2015. In December 2014, an application was filed for an additional once-through steam generator and high pressure boiler feedwater pump.

Phase 1

30,000

2006

OP

P R O J E C T S TAT U S

CURRENT PROJECT

CAPACITY

REGULATORY STATUS

START-UP

Cold Lake

Updated: Jun 2015

Imperial has submitted an application to the Alberta Energy Regulator for the expansion of the LASER treatment for implementation in 2017. The company says that steam injection at the Nabiye expansion project began in January. Bitumen production has started on schedule.

Phase 1-10 Phase 11-13 Experimental SA-SAGD Phase 14-16

110,000

1985

OP

30,000

2002

OP

TBD

2013

OP

40,000

2015

OP

OSUM Oil Sands Corp.

•

Orion

10,000

2007

OP

Phase 2

10,000

TBD

Approved

Taiga

Updated: Mar 2015

OSUM says that Taiga Phase 1 will be advanced in 2015-16 subject to financing.

Phase 1

12,500

TBD

Approved

Phase 2

12,500

TBD

Approved

Phase 3

20,000

TBD

Approved

Pengrowth Energy Corporation Lindbergh

Updated: Jun 2015

Pengrowth is increasing its capital spending at Lindbergh in 2015 by $20 million. The budget is now $220 million to $240 million for the year.

Phase 1 Phase 1 Optimization Phase 2 Expansion

Terre de Grace Pilot •

Phase 1

12,000

2014

OP

Phase 2B

45,000

2016

UC

Phase 3

80,000

2017

UC

Ivanhoe Energy Inc. •

Tamarack

Updated: Jun 2015

Ivanhoe has announced that despite considerable efforts by the company, its trustee and major creditors, the parties have been unable to reach a viable restructuring proposal under the Bankruptcy and Insolvency Act. The company was deemed bankrupt as of 11:59 p.m.

MDT on June 1.

Phase 1

34,784

TBD

APPL

Suncor Energy Inc. Base Operations

Updated: May 2015

Suncor reported record synthetic crude oil production in the first quarter due to strong upgrader reliability. Production is expected to decrease in the second quarter due to planned coker maintenance.

U1 and U2

225,000

1967

OP

Millennium Vacuum Unit

35,000

2005

OP

TBD

HOLD

Millennium Coker Unit

97,000

2008

OP

34,000

Syncrude Canada Ltd. Mildred Lake/Aurora Updated: Jun 2015

1,400

2014

OP

Updated: May 2015

Syncrude has filed the regulatory application for the MLX project. During 2015, Syncrude is focusing on cost reduction to remain profitable during the low oil price environment.

Base Plant Stage 1 & 2 Debottlenecking

250,000

1978

OP

Stage 3 Expansion (UE-1)

100,000

2006

OP

TBD

ANN

Stage 3 Debottlenecking

75,000

SOUTH ATHABASCA REGION — UPGRADER CNOOC Limited Long Lake

Updated: Mar 2015 2,000

2011

TBD

2011

OP Updated: Feb 2013

Updated: Apr 2015

An application was filed in early March to amend production capacity at Kinosis 1B to 37,500 bbls/d. Plans for the remaining 12,500 bbls/d (of the 70,000 bbls/d approved) have not been disclosed. Five week shutdown scheduled for the Long Lake Upgrader starting June 1.

OP

Phase 1

58,500

2009

OP

Value Creation Inc. Updated: May 2015

TBD 12,450

TBD

OP

2019

APPL

Advanced TriStar

Sawn Lake

Updated: Jun 2014 700

TBD

Harmon Valley South

Updated: Sep 2014 TBD

2014

OP

75

2011

OP

TBD

APPL

Seal Main

Updated: Mar 2015 10,000

Royal Dutch Shell plc Peace River

1986

OP

Carmon Creek - Phase 1

40,000

2019

UC

Carmon Creek - Phase 2

40,000

TBD

Approved

Touchstone Exploration Inc. Dawson

Updated: May 2015

Touchstone announced in October 2014 that it has suspended its project.

TBD

2014

SUSP

TBD

APPL

25,500

TBD

APPL

ATS-3

25,500

TBD

APPL Updated: May 2014

Pilot

12,000

2018

APPL

INDUSTRIAL HEARTLAND REGION — UPGRADER North West Upgrading Inc. Redwater Upgrader

Updated: May 2015

Gemini Corporation has been awarded a $21-million contract by TR Canada Inc. for the assembly of certain process modules. Assembly will take place at Gemini’s Ponoka, Alta., facility.

Updated: May 2015

12,500

12,750

ATS-2

Value Creation has filed an amendment to its regulatory approval to increase production capacity from 1,000 to 6,000 bbls/d.

Shell says it will delay start-up of the first phase of Carmon Creek from 2017 to 2019 as the company looks to achieve cost reductions.

Cadotte Lake

ATS-1

DOEx (Demonstration of Excellence)

Approved

Penn West Petroleum Ltd.

Updated: Mar 2015

The Alberta Energy Regulator says it will defer decisions on applications for in situ oilsands projects in the new shallow thermal area of the Athabasca region until it has developed formal regulatory requirements. Advanced TriStar is one of five impacted projects.

Northern Alberta Oil Ltd.

Experimental Demonstration

OP

Phase 2A

UC

Seal/Cadotte

Commercial

OP

2014

OP

About 250 bbls/d of production is currently shut in at Seal. Murphy says that in the worst case scenario, up to 80 wells could be shut in.

Pilot

2009

5,000

2015

Murphy Oil Company Ltd.

Pilot

110,000

Reliability - Tranche 2

3,500

Harmon Valley

Pilot

Updated: Jun 2015

OP

Cliffdale

Demonstration

Horizon

Canadian Natural says that its 2015 maintenance turnaround has been accelerated to June from the fall. Overall, the company says its Phase 2/3 expansion is approximately 60 per cent physically complete.

2015

Baytex Energy Corp.

Pilot

Approved

2012

Andora majority owner Pan Orient Energy says the well is still in its ramp-up phase. During March 2015, bitumen sales averaged 319 bbls/d with a steam to oil ratio of 5.4:1. The company expects the steam chamber to reach the top of the Bluesky Formation sandstone reservoir in April 2015, and maximum production is anticipated to occur in approximately September 2015, corresponding to the end of the first year of production.

Pilot

TBD

1,260

Sawn Lake

Pilot

8,400

Canadian Natural Resources Limited

Andora Energy Corporation

Demonstration

Updated: Apr 2014

11,240

PEACE RIVER REGION — IN SITU •

REGULATORY STATUS

BP says that ongoing appraisal activities continue.

Updated: Jun 2015

Phase 1

Pilot

START-UP

BP p.l.c.

OSUM appears to be acheving meanginful progress increasing production and improving efficiency at the Orion project. According to Alberta Energy Regulator data, production in March averaged 9,371 bbls/d with a steam to oil ratio of 2.32:1.

•

CAPACITY

NORTH ATHABASCA REGION — UPGRADER

Imperial Oil Limited •

CURRENT PROJECT

Phase 1

50,000

2017

UC

Phase 2

50,000

TBD

Approved

Phase 3

50,000

TBD

Approved

Shell Albian Sands •

Scotford Upgrader

Updated: Jun 2015

Shell has made a final investment decision on the HCU debottleneck project, which is expected to increase hydrocracking capacity by about 20 per cent.

Commercial

155,000

2003

OP

Expansion

100,000

2011

OP

TBD

ANN

Scotford HCU Debottlenecking

14,000

JULY / AUGUST 2015 | OILSANDSREVIEW.COM

29

Thrive in a $60/bbl environment Despite reductions in capital budgets, investment in small and sustaining capital projects and maintenance, repair and operations (MRO) is expected to approach $39 billion in 2017.

How can service and supply companies capture a share of this planned oilsands spend?

Purchase the latest CanOils Market Intelligence Report, Hunting opportunities: Following the producer spend in a bear oilsands market. You’ll get specific, actionable recommendations right down to which companies are poised as prime clients and what they expect from providers in this new cost structure environment.

Regional spending breakdown

S

P AM

LE

GR

H AP

A AT &D

TOTAL % INCREASE (2014-2017 EST.) PEACE RIVER Maintenance, repair and operations

19%

Small project and sustaining CapEx

96%

NORTH ATHABASCA Fort McMurray

Maintenance, repair and operations

405%

Small project and sustaining CapEx

8%

Includes supporting metrics on:

CENTRAL ATHABASCA*

Edmonton

Calgary

Maintenance, repair and operations

27%

Small project and sustaining CapEx

47%

SOUTH ATHABASCA Maintenance, repair and operations

67%

Small project and sustaining CapEx

74%

COLD LAKE Maintenance, repair and operations

9%

Small project and sustaining CapEx

33%

The size of addressable spend Categories of spend that remain strong Where spend is planned to occur geographically and with which companies

* Central Athabasca has been defined as the area that is within a 70-kilometre driveable radius from Fort McMurray

Re-align your business to capitalize on continuing spend.

Download Hunting opportunities: Following the producer spend in a bear oilsands market.

canoils.com

Monthly crude oil prices Cold Lake blend

Light sour

Condensate

985 kg/m3 3.5% sulphur bitumen

West Texas Intermediate (spot price at Cushing, Okla.)

statistics

Source: Flint Hills Resources Ltd./Energy Information Administration

Bow River

Western Canadian Select

Brent (Europe spot price)

$120

$100

The inputs to and outputs of the oilsands industry.

$80 wtd price (US$/bbl)

For suggestions or data contributions, please contact Deborah Jaremko, djaremko@junewarren-nickles.com.

Natural gas: Spot prices at AECO trading hub in Alberta

$40 Source: Natural Gas Exchange Inc.

Monthly averages to Jun. 3, 2015.

$5.00

C$/GJ

$4.00 $3.00

$2.67

$2.00 $1.00 $0

Jun

Jul

2014

Aug

Sep

Oct

Nov

Dec

Jan

Feb

2015

$60

Mar

Apr

May

$20

$0

Dec 1

Jan 2

2014

$60

$32.28

$40 $20

2014

Sep

Oct

Nov

Reinforcing bar

Dec

Jan

2015

Feb

Mar

$850

$750

$800 US$/tonne

US$/bbl

$80

Aug

Structural sections and beams

Source: MEPS International

Source: Natural Gas Exchange Inc.

$100

Jul

May 1

$900

Calculated using NetThruPut Monthly WCS Index.

Jun

Apr 1

North American carbon steel prices

Bitumen royalty valuation at Hardisty, Alta.

May

Mar 2

Jun

Hot rolled coil

$0

Feb 2

2015

$750 $700

$627

$650 $600

$541

$550 $500

Apr

Jun

2014

Jul

Aug

Sep

Oct

Nov

Dec

Jan

2015

Feb

Mar

Apr

May

Alberta oilsands lease sales

June 2014

HECTARES

1,792

Cold Lake $/HECTARE

$118.24

July 2014 August 2014

1,280

Peace River $/HECTARE

$602.62

HECTARES

$/HECTARE

0

$0.00

0

$0.00

0

$0.00

NO PUBLIC OFFERING NOTICES 0

$0.00

September 2014 October 2014

HECTARES

319

$58.13

NO PUBLIC OFFERING NOTICES 0

$0.00

November 2014

6,272

$42.74

NO PUBLIC OFFERING NOTICES

December 2014

0

$0.00

2,816

$43.66

2,048

$16.91

January 2015

0

$0.00

3,648

$38.11

0

$0.00

February 2015 March 2015

Source: Alberta Department of Energy

Athabasca SALE MONTH

NO PUBLIC OFFERING NOTICES 0

$0.00

1,536

$65.85

19,008

$1,105.37

April 2015

19,456

$16.61

2,048

$89.54

0

$0.00

May 2015

5,120

$2.55

0

$0.00

0

$0.00

JULY / AUGUST 2015 | OILSANDSREVIEW.COM

31

S TAT I S T I C S

Mined bitumen and synthetic crude oil production (bbls/d)

Suncor Energy Inc.

PROJECT Base operations Mildred Lake

Syncrude Canada Ltd.

Aurora North and South Muskeg River

Shell Albian Sands

Jackpine Scotford Upgrader

Canadian Natural Resources Limited

Horizon

Nexen Energy ULC

Long Lake SAGD

Imperial Oil Limited

Kearl

Three-month average

DEC 2014

JAN 2015

FEB 2015

Bitumen

312,836.9

323,785.9

319,990.1

318,871

Synthetic crude

336,723.0

346,606.9

372,143.2

351,824

Bitumen

79,371.1

120,900.5

154,258.7

118,177

Synthetic crude

219,409.0

299,688.3

313,674.2

277,590 202,321

Bitumen

173,442.4

220,865.5

212,655.4

Synthetic crude

---

---

---

---

Bitumen

142,978.3

136,673.4

147,053.0

142,235

Synthetic crude

---

---

---

Bitumen

128,111.7

104,539.7

111,870.5

114,841

Synthetic crude

---

---

---

---

Bitumen

---

---

---

---

Synthetic crude

268,331.1

283,524.4

250,370.2

267,409

Bitumen

153,680.3

157,886.6

158,816.7

156,795

Synthetic crude

135,487.6

137,305.2

319,428.6

197,407

Bitumen*

---

---

---

---

Synthetic crude

34,151.9

31,495.6

36,372.5

34,007

Bitumen

94,464.4

87,097.9

121,143.6

100,902.0

Synthetic crude

---

---

---

---

Source: Alberta Energy Regulator

OPERATOR

*Bitumen production listed is mined bitumen and therefore does not apply to the Long Lake in situ project.

Alberta in situ bitumen production

OPERATOR

PROJECT

JAN 2015

FEB 2015

MAR 2015

Three-month average

Suncor Energy Inc.

Firebag

186,518.0

191,425.4

186,965.9

Cenovus Energy Inc.

Christina Lake

153,955.1

152,188.3

151,991.4

152,711.6

Imperial Oil Limited

Cold Lake

147,639.5

147,277.8

158,732.2

151,216.5

Cenovus Energy Inc.

Foster Creek

142,135.3

128,584.5

135,898.9

135,539.6

Canadian Natural Resources Limited

Primrose & Wolf Lake

113,800.9

134,810.8

117,197.4

121,936.4

MEG Energy Corporation

Christina Lake

82,102.2

81,684.5

83,340.0

82,375.6

Devon Canada Corporation

Jackfish

77,885.5

80,224.6

81,743.0

79,951.0

CNOOC Limited

Long Lake

38,802.5

40,048.5

45,064.6

41,305.2

Suncor Energy Inc.

Mackay River

31,089.9

32,035.9

24,858.0

29,327.9

Canadian Natural Resources Limited

Kirby South

24,474.3

24,216.4

23,242.7

23,977.8

ConocoPhillips Canada Limited

Surmont

22,413.7

25,334.1

23,918.3

23,888.7

Statoil

Leismer Demonstration

18,755.6

15,451.5

16,004.4

16,737.2

Connacher Oil And Gas Limited

Great Divide

15,504.4

14,672.9

14,995.5

15,057.6

Husky Energy Inc.

Tucker

10,295.2

10,342.3

10,371.9

10,336.5

OSUM Oil Sands Corp.

Orion

6,506.8

9,325.9

9,371.2

8,401.3

Japan Canada Oil Sands Limited

Hangingstone Pilot

5,715.6

5,509.9

5,406.7

5,544.0

Royal Dutch Shell plc

Peace River/Carmon Creek

4,233.0

4,587.8

4,851.3

4,557.4

Pengrowth Energy Corporation

Lindbergh Pilot

1,771.2

2,760.6

4,983.4

3,171.7

Southern Pacific Resource Corp.

STP-McKay

1,907.1

1,935.4

1,875.6

1,906.0

Grizzly Oil Sands Ulc

Algar Lake

800.1

756.7

1,135.3

897.3

Baytex Energy Corp.

Cliffdale Pilot

725.8

734.6

785.0

748.5

Imperial Oil Limited

Experimental SA-SAGD Cold LK

534.0

529.6

632.8

565.5

Baytex Energy Corp.

Gemini

419.5

525.8

634.0

526.5

BlackPearl Resources Inc.

Blackrod

454.1

390.6

439.0

427.9

Laricina Energy Ltd.

Germain

785.6

423.3

---

403.0

ConocoPhillips Canada Limited

Surmont Pilot

390.0

393.7

371.1

384.9

Andora Energy Corporation

Sawn Lake

244.7

294.4

329.6

289.5

Cenovus Energy Inc.

Grand Rapids Pilot

285.6

267.9

220.8

258.1

Penn West Petroleum Ltd.

Harmon Valley South Pilot

316.4

153.5

113.8

194.6

Laricina Energy Ltd.

Saleski Pilot

193.1

110.1

133.3

145.5

Husky Energy Inc.

Sunrise

---

---

422.7

140.9

Penn West Petroleum Ltd.

Seal Main Pilot

88.7

81.1

76.7

82.2

Murphy Oil Company Ltd.

Seal/Cadotte Pilot

90.6

42.1

50.3

61.0

TOTAL COMMERCIAL

1,090,833.7

1,107,120.5

1,106,156.9

1,101,370.4

32

OILSANDS REVIEW | JULY / AUGUST 2015

188,303.1

TOTAL PRIMARY

274,241.4

272,991.0

269,208.9

272,147.1

TOTAL CONVENTIONAL

2,634.8

2,572.5

2,734.8

2,647.4

TOTAL

1,367,709.9

1,382,684.1

1,378,100.7

1,376,164.9

Source: Alberta Energy Regulator

Commercial in situ schemes production rates per calendar day (bbls/d), listed in descending order of production for last month of data set.

S TAT I S T I C S

FirstEnergy oilsands, integrated and large cap indexes Integrated

Source: FirstEnergy Capital Corp.

Oilsands

Recorded until Jun. 2, 2015.

Large cap

120

INTEGRATED

110

20.73

100

$88.15

90

$85.87

80

since Jun. 2, 2014

LARGE CAP

18.98

70

since Jun. 2, 2014

60 50

OILSANDS 40

$29.50

30

30.43

since Jun. 2, 2014

20 May

2014

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Jan 2015

Feb

Mar

Apr

May

June

Index launched Jan. 1, 2007. FirstEnergy complimentary indexes are available daily on the homepage at firstenergy.com. FirstEnergy Capital Corp. is a member of the Canadian Investor Protection Fund and IIROC.

Thermal oilsands project steam to oil ratios Source: Alberta Energy Regulator

Listed in ascending order for six-month SOR average.

OPERATOR

FIELD

JAN 2015

FEB 2015

MAR 2015

Three-month average

Cenovus Energy Inc.

Christina Lake

1.65

1.65

1.66

1.65

Baytex Energy Corp.

Cliffdale Pilot

2.14

1.83

1.59

1.85

BlackPearl Resources Inc.

Blackrod

2.43

1.04

2.35

1.94

Baytex Energy Corp.

Gemini

2.34

2.12

2.22

2.23

OSUM Oil Sands Corp.

Orion

2.61

1.75

2.32

2.23

Cenovus Energy Inc.

Foster Creek

2.36

2.38

2.39

2.38

ConocoPhillips Canada Limited

Surmont

2.14

2.48

2.72

2.45

Devon Canada Corporation

Jackfish

2.52

2.46

2.51

2.50

MEG Energy Corporation

Christina Lake

2.56

2.60

2.51

2.56

Suncor Energy Inc.

Firebag

2.62

2.59

2.60

2.60

Canadian Natural Resources Limited

Kirby South

2.72

2.74

2.78

2.75

Suncor Energy Inc.

Mackay River

2.86

2.80

2.78

2.81

Statoil

Leismer Demonstration

3.06

2.86

2.90

2.94

Laricina Energy Ltd.

Germain

4.74

4.79

---

3.18

ConocoPhillips Canada Limited

Surmont Pilot

3.39

3.34

3.42

3.38

Canadian Natural Resources Limited

Primrose & Wolf Lake

3.64

3.01

3.84

3.50

Connacher Oil And Gas Limited

Great Divide

3.60

3.71

3.74

3.68

Royal Dutch Shell plc

Peace River/Carmon Creek

4.56

4.52

2.35

3.81

CNOOC Limited

Long Lake

4.23

3.96

3.95

4.05

Cenovus Energy Inc.

Grand Rapids Pilot

3.20

3.65

5.39

4.08

Imperial Oil Limited

Cold Lake

3.89

4.33

4.24

4.15

Japan Canada Oil Sands Limited

Hangingstone Pilot

4.98

4.89

4.76

4.88

Southern Pacific Resource Corp.

STP-McKay

6.31

6.27

6.44

6.34

Husky Energy Inc.

Tucker

6.38

6.35

6.78

6.50

Grizzly Oil Sands Ulc

Algar Lake

7.27

8.96

6.14

7.46

Pengrowth Energy Corporation

Lindbergh Pilot

11.96

11.23

5.58

9.59

Husky Energy Inc.

Sunrise

---

---

80.42

26.81

JULY / AUGUST 2015 | OILSANDSREVIEW.COM

33

S TAT I S T I C S

Alberta crude bitumen and synthetic crude production 2013-14 Synthetic crude

45,000

Thousand barrels

40,000 35,000

Nov. 2013 total:

30,000

61,949,000

31,667,900 bbls or 51.1%

bbls

30,281,100 bbls or 48.9%

10,000

Nov. 2014 total:

35,866,800 bbls or 53.6%

5,000

66,972,700

Source: Alberta Energy Regulator

Crude bitumen

25,000 20,000 15,000

0

bbls

Nov

2013

Dec

Jan

2014

Feb

Mar

Apr

May

Jun

Jul

Aug

Sep

Oct

Nov

31,105,900 bbls or 46.4%

Dec*

*December crude bitumen data not available from Alberta Energy Regulator at press time.

Crude oil differential: WTI-WCS

Differential: West Texas Intermediate to Western Canadian Select (US$/bbl)

30 25 20 15

May 2015 Avg $8.77

Apr 2014 Avg $25.75

10 5 0

8.55

Apr 2015 Avg $10.41 Apr

2014

May

Jun

Jul

Aug

Sep

Oct

Nov

Dec

Jan

2015

Feb

Mar

Apr

May

FirstEnergy Capital Corp. crude differentials update Canadian heavy crude prices have recently been scoring some of the best price differentials in five years. The Western Canadian Select (WCS)-WTI price spread has traded as tight as a US$8/bbl discount to WTI in recent weeks, and has been consistently improving since the start of the year.

Oilsands production facility maintenance has been playing a role in helping tighten price differentials of late, impacting up to 100,000 bbls/d of supply. The tighter supply, combined with a strong seasonal upswing in refinery demand, has helped to boost price bids for WCS. The expansion of crude oil pipelines in the U.S. Midwest and to the U.S. Gulf Coast has enhanced market access for Canadian heavy crude oil. With many U.S. Gulf Coast refiners

34

OILSANDS REVIEW | JULY / AUGUST 2015

more geared to running heavier barrels, WCS is starting to find more buyers in this market. Greater access to the U.S. Gulf Coast has also provided that WCS is now in more direct competition with Maya, its Mexican counterpart crude. The end result has been a stronger price bid up the chain of supply. The rising tide of crude oil moving by rail has also created a secondary channel for Canadian crude oil to reach markets.

In the next few months, Enbridge is expected to start up its Line 9 Pipeline reversal, providing another passage for improved market access. Line 9 will allow light and heavy crude oil to flow eastward from Hamilton, Ont., back to Montreal, Que., and should help displace imported barrels into the East Coast of Canada.

Since improved market access is likely to continue in the near term, and it is increasingly likely that more Canadian barrels will be re-exported from the U.S. Gulf Coast, we expect that Canadian crude oil will finally be getting prices that are a little more world-class in the coming years.

As such, we think that Canadian production will be fetching a much better relative price in the next few years than anything seen in the previous five years. The current climate represents one of the best opportunities for Canadian crude oil producers to further lock in strong pricing and unparalleled growing market access for its product.

— Martin King, vice-president, institutional research, FirstEnergy

Source: FirstEnergy Capital Corp.

Recorded until Nov. 24, 2014.

Recorded until Aug 20, 2014.

transition CLEAN ENERGY COMMENTARY FROM THE PEMBINA INSTITUTE

Alberta’s new tailings management framework is encouraging, but skepticism about regulation compliance is justified

BY ERIN FLANAGAN

T

here are few oilsands images as iconic, or as troubling, as the vast lakes of tailings waste sprawling the landscape in northeastern Alberta. According to Alberta Environment and Sustainable Resource Development, dams, dykes, ponds and beaches in the region contain more than 970 billion litres of toxic liquid and cover a full 220 square kilometres.

Since the inception of the oilsands mining industry, companies have grappled with how to treat, store and ultimately reclaim tailings, the by-product of their extractive business.

But despite continued technology deployment and innov­ ation, progress on this critical issue has been disappointing.

Industry has faced enormous technical challenges working to settle out the sand, clay and other fine particles from a suspended form following the bitumen mining process. The technical challenge has been to settle out this liquid in an expedient and cost-effective manner in order to ultimately re-create a solid landscape and recover and re-use the process-affected water. The total amount of tailings continues to grow year over year, and it will be decades before the economic and environmental liability to Albertans is resolved.

Those familiar with the mining industry know the consequences of growing tailings inventories, from fatal impacts to birds and other wildlife to toxic seepage and delayed reclamation. In 2008, over 1,600 migratory ducks perished after landing on tailings at Syncrude’s Aurora mine. The company faced federal and provincial charges for the incident and ultimately paid a fine totalling $3 million.

Other environmental impacts may be less visually arresting, but they are no less troubling. For years, First Nation communities and environmental groups have been

drawing attention to the concern that tailings lakes are seeping toxic compounds into the region’s aquatic environment, including the Athabasca River and its tributaries. In 2010, the Pembina Institute was stunned to discover the total volume of tailings process–affected water likely seeping into the aquatic environment was 11 million litres per day. The impacts to the environment from tailings seepage are highly contested and remain inadequately monitored despite assurances by the federal and provincial government that credible scientific water monitoring programs in the oilsands region will be established.

All stakeholders can agree that tailings are bad for the environment and bad for business. Despite ongoing technical challenges, we remain hopeful that 2015 will see major progress on this critical issue facing the oilsands.

A new era of tailings management?

The Pembina Institute was encouraged to see the Government of Alberta unveil a new tailings management framework in March of this year. The Tailings Management Framework for the Mineable Athabasca Oil Sands (TMF) represents the first policy in Alberta to set targets for both legacy tailings—those produced between 1967 and 2015—and new tailings that will be created as mining projects continue their operations. It provides preliminary guidance to industry regarding the need to reduce legacy tailings on the landscape and sets holistic targets to ensure industry achieves its closure commitments.

Because it takes a longer-term view, and because it sets out rules for the management of legacy tailings, the TMF represents an improvement over existing management practices. It establishes a trajectory for new

JULY / AUGUST 2015 | OILSANDSREVIEW.COM

35

TRANSITION

tailings production and applies a trigger and limit system to gauge whether operators are achieving their intended treatment plans. Operators can also accumulate between three to 10 years worth of new tailings before they are expected draw down their inventory in the aims of achieving end-of-mine-life commitments.

Despite these new steps in the right direction, scepticism is justified. The Government of Alberta has so far been ineffective at stopping the overall growth of tailings, let alone reducing tailings volumes. In 2009, Alberta’s energy regulator released new rules to manage growing volumes of tailings waste—Directive 074: Tailings Performance Criteria and Requirements for Oil Sands Mining Schemes. The directive established annual clean-up targets for industry and set conditions for the trafficability of tailings deposits, a measure used to track whether treated tailings are solid enough to support motorized traffic and eventual reclamation. Directive 074 only applied to tailings produced after 2009, leaving a large volume of legacy tailings unregulated.

Progress on tailings management is critical for public confidence in the industry. We hope the AER is up to the challenge.

According to the regulator’s last public update, not a single company was complying with the directive—and despite year-over-year lack of compliance on the part of industry, it was never enforced. The Alberta Energy Regulator (AER) recently suspended Directive 074, in light of the new TMF policy direction. Moving forward, it’s critical that the AER develop and enforce firm limits on tailings accumulation.

A framework with too many loopholes Pembina’s initial assessment of the framework shows its effectiveness could be limited by its permissive approach to inventory oversight and management. As currently articulated, the framework is too flexible to non-compliance from operators. It tolerates up to a 20 per cent deviation from forecasted tailings production on an annual basis and up to 40 per cent from forecasted end-of-mine-life volume.

Modifying the framework to tolerate less deviation from intended tailings trajectories would increase its usefulness as a tool to protect Albertans from environmental and economic liabilities. Furthermore, three to 10 years is too vague. The regulator, not industry, must set clear

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performance targets so Albertans can be confident tailings are being dealt with in an aggressive manner.

The framework will only be effective if matched with clear implementation and enforcement mechanisms. For that reason, we suggest Alberta modify the framework to ensure enforcement actions are introduced earlier over the course of a project’s life. Despite stating that companies are required to post additional financial security to the Mine Financial Security Program (MFSP), Alberta has yet to determine the rate and frequency at which companies pay in to the program. The MFSP penalty must be high enough to act as a deterrent against simply paying into a fund. It must also be more expensive than the average cost of implementing best available tailings technologies.

Heavy lifting left to the Alberta Energy Regulator In addition to the loopholes identified within the framework, a very significant portion of work has been left for the AER to resolve. First and foremost, the regulator is tasked with the vetting of industry tailings management plans and determining whether each company is pursuing ambitious and fair strategies to reduce their impact on the environment. This process will no doubt draw public attention. Despite continued assurances that the existing tailings on our landscape would soon disappear, total volumes have increased year over year.

In addition to the vetting of tailings profiles, the AER must also establish standards for progressive reclamation activities, the return of process-affected water to the environment and the modification of the MFSP to capture economic liability. If your palms are sweaty simply reading that important but daunting list of undertakings, you aren’t alone. It’s clear the AER will need to collaborate with experts across the sector and the province to solicit feedback and advice as it crafts its implementation plan. We urge the AER to seek participation from a broad group of stakeholders to ensure that a multitude of perspectives are heard and, ultimately, that the tailings framework has a baseline level of credibility and support across the province.

Working towards real progress Without question, many in industry and government take the problem of tailings management very seriously and are working hard to eliminate it. But clear, measurable and transparent progress remains essential to rebuild public confidence in the sector’s tailings practices. For too long, Albertans have been left with insufficient information on a critical issue.

For such an important social and environmental issue, this trend has been completely unacceptable. Progress on tailings management is critical for public confidence in the industry. We hope the AER is up to the challenge.

Erin Flanagan is an analyst with the Pembina Institute, specializing in oilsands and pipelines-related policy.

upcoming events OILSANDS HAPPENINGS TO CALENDAR

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Monday, July 6

Monday, August 24

Boots, Buckles & Brews—Canadian Heavy Oil Association Stampede Lunch

Canadian Heavy Oil Association Calgary Golf Tournament

Knoxville’s Tavern (tent), Calgary choa.ab.ca/events

Priddis Greens Golf & Country Club choa.ab.ca/events

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For more events, please visit:

events.nickles.com

Syncrude’s Sandhill fen research project in June 2014. The 57-hectare reclamation site, built atop the former East Mine, was the recipient of the Towards Sustainable Mining Award for Environmental Excellence in May 2014. The area sits just adjacent to Highway 63 and the Syncrude upgrader, seen at the top of the photo.

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JULY / AUGUST 2015 | OILSANDSREVIEW.COM

37

sector watch QUICK-HIT INSPECTION OF OILSANDS ISSUES

Andrew Leach: Why the environmental spotlight on the oilsands is about to get even brighter

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ilsands producers are used to intense scrutiny on environmental issues, but they may find the spotlight especially bright in the coming months.

Nations from around the globe will be gathering in Paris at year-end to attempt to hammer out a climate change agreement, and any discussion of Canada’s carbon footprint inevitability will turn to the oilsands. For proof of the size of the challenge facing the industry, just look to the results of a recently released study co-produced by the University of Calgary, which ranked 30 different types of crude based on life-cycle emissions. The worst offender? Suncor Energy’s Synthetic H blend.

“You can talk a lot about small oilfields in California or little oilfields in other places, but if you get to a big oil production play, oilsands is by far the highest [greenhouse gas emitter],” said Andrew Leach, associate professor of energy policy at the University of Alberta, during a speech at the Innovation in Construction Forum in Edmonton in April. “Suncor is not the highest among them, but Suncor was their test case for synthetics.”

The oilsands can work under a carbon pricing system, he noted. The greater question, however, is not what sort of pricing system might be imposed domestically, but rather what the rest of the world will do to

“You can talk a lot about small oilfields in California or little oilfields in other places, but if you get to a big oil production play, oilsands is by far the highest [GHG emitter].”

— Andrew Leach, associate professor of energy policy, University of Alberta

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penalize emissions. The perception that Alberta is not doing enough to respond to oilsands environmental impacts will likely only spur further international pressure on the industry.

Of course, Leach had no way of knowing that he was speaking from the dying days of a dynasty at the time.

Several weeks after his speech, the New Democratic Party was elected government of Alberta—ending 43 years of Progressive Conservative rule—and in the process created an opportunity to reset the province’s environmental reputation. But any talk of the fledgling government’s oilsands agenda remains largely speculative at this early point in the regime changeover.

“I don’t think we know enough yet,” he wrote in a follow-up email with Oilsands Review. “We’ll see what policies they look to impose.”

Leach has several ideas on how to help Canada’s environmental record, including implementing national regulations that consider all industrial development.

For example, drawing upon Alberta’s Athabasca River monitoring regime, Canada should invest in similar programs for the four most polluted watersheds in Ontario and Quebec, he suggested. New rules would have to take into account the interests of not only the oilsands, but also eastern Canadian farmers, steel workers, cement manufacturers and other industries.

The same strategy could be employed on the issue of greenhouse gas emissions. Instead of fighting against tighter standards, the industry should embrace the same rules faced by heavy industries in other parts of the country. There is no reason a refinery or mine in Ontario should be considered any differently than one in Alberta, Leach argued.

“Get out in front and say, ‘We can take on this regulation—can you?’” he said. “Let the other industries talk the regulation down.”

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