Background

Alberta’s oil sands contain roughly 170 billion barrels of oil in the form of bitumen recoverable using today’s technology, making Alberta’s reserves the second largest in world. In 2009, production of oil sands crude (a combination of bitumen and synthetic crude oil (SCO) upgraded from bitumen) in the Province was 1.3 million barrels per day (bpd). In view of renewed investment and development initiatives undertaken by a wide variety of producers and other participants, the Canadian Association of Petroleum Producers (CAPP) estimates that production from oil sands will be 2.2 million bpd by 2015 and as high as 3.5 million bpd by 2025.

The Economy

The last two years have served as a demonstration of the impact of the global economy on the feasibility and appeal of oil sands investment and development. Volatility in the price of oil, global economic woes and tightening of credit markets resulted in a lull in Alberta’s oil sands development in the 12 months leading up to Q3 2009. As much as $90 billion worth of oil sands development was delayed, deferred or cancelled entirely. However, credit markets have since revived and the price of crude oil has rebounded significantly, hovering between $70-90 per barrel in Q2 2010. These stronger oil prices, potential decreases in the capital costs of project development, and the assurance of consistent and sustainable operating costs have renewed oil sands investment opportunities. CAPP now estimates oil sands industry capital expenditure will increase to $13 billion in 2010 from $11 billion spent in 2009. While renewed growth in the oil sands industry is readily apparent, development is expected to be slower and more tempered, which was not the case two years ago when the price of crude hit $147 per barrel.

In 2008, at the height of the boom in oil sands development, the National Energy Board (NEB) estimated that production costs per barrel would increase to as much as $50-60 for in-situ extraction and $55-65 for new mining extraction and upgrading projects. According to reports published in Oilsands Review with respect to a few of the larger active mining and in-situ projects, and with the notable exception of Suncor Energy Inc.’s (Suncor) increased costs due to unplanned maintenance resulting from upgrader fires, operating costs have remained relatively stable and significantly lower than NEB estimates. For Q1 2010 Syncrude Canada Ltd. (Syncrude) reported operating costs of $41.81 per barrel of SCO, and production costs of $25.37 per barrel of bitumen. Canadian Natural Resources Limited (CNRL) has reported a similar $43.12 per barrel of SCO. Meanwhile, Cenovus Energy Inc. (Cenovus) and ConocoPhillips Canada (ConocoPhillips) have reported in-situ operating costs of $16.41 per barrel of bitumen produced at Christina Lake and $11.11 per barrel of bitumen produced at Foster Creek.

A Revived Investment Climate

The ConocoPhillips and Total E&P Canada Ltd. (Total) joint venture announced in January 2010 that they plan to quadruple production at their Surmont lease from 27,000 to 110,000 bpd by 2015, with construction to begin later this year. Husky Energy Inc. (Husky) and BP Canada’s (BP) construction on the $2.5-billion Sunrise project was slated to begin in the second half of this year. Imperial Oil Limited (IOL) is forging ahead with the $8-billion mining development of its Kearl Lake lease, as is Devon Energy Corporation with its in-situ expansion at Jackfish. Suncor has confirmed its intention to complete development of Stages 3 and 4 of the Firebag in-situ project. BP also demonstrated a renewed interest in oil sands growth when it purchased a majority partnership stake and operatorship in the development of Value Creation Inc.’s Terre de Grace lease.

Foreign Investment (Asia)

One major trend particularly noteworthy in 2010 is that significant investment is incoming from Asia, in particular from major Chinese companies. PetroChina Company Limited (PetroChina), China’s largest publically listed oil producer, announced in January that it had completed a C$1.9 billion acquisition of a 60% interest in Athabasca Oil Sands Corp.’s MacKay River and Dover in situ oil sands projects. China National Offshore Oil Corporation (“NOOC) maintains a 17% interest in MEG Energy Corp., a Canadian-based oil sands developer. In a deal that closed in June of this year, China Petroleum & Chemical Corporation (Sinopec) acquired Conoco-Phillips’ 9.03% interest in Syncrude for $4.65 billion. Korea National Oil Corp. recently submitted an environmental impact assessment report regarding the expansion of its Blackgold Project which would add 20,000 bpd of capacity to its initial 10,000 bpd in-situ project. Japan Canada Oil Sands Limited (JACOS) is currently operating a 10,000 bpd SAGD pilot project at its Hangingstone lease, and a 35,000 bpd expansion of this project is proposed for development through a joint venture with Nexen Inc., who holds a 25% interest.

Smaller Player / Small Scale Project Development

There has also been a resurgence in small scale oil sands development, particularly for in-situ projects. Calgary-based Osum Oil Sands Corp. has submitted an application for a 35,000 bpd in-situ project near Cold Lake in eastern Alberta. Alberta Oilsands Inc. has applied for approval of a pilot in-situ project to produce 4,500 bdp of bitumen in the Clearwater area just southeast of Fort McMurray, with a goal of eventually producing 10,000 bpd using steam assisted gravity drainage (SAGD) technology. Laricina Energy Ltd. recently applied for approval of an expansion to 5000 bpd of its Germain Pilot Grand Rapids project using solvent-cyclic SAGD technology, and is moving forward with a 1,800 bpd Carbonate SAGD demonstration project on its Saleski lease. MEG Energy Corp.’s Christina Lake Phase 2 expansion is underway and is set to produce 22,000 bpd. Southern Pacific Resources Corp. plans to begin construction on its 12,000 bpd STP-MacKay in-situ project later this year, and Sunshine Oilsands Ltd. has received Provincial approval to develop its 1000 bpd Muskwa Project.

Small scale project development, often in the form of an initial pilot project, has some advantages over truly large-scale developments in that it allows the developer to apply more innovative and potentially cost saving and /or environmentally friendly technologies to the proposed extraction process (see below). The relatively short ramp-up to full capacity allows for quicker realization of the planned economies of scale resulting in potentially more predictable and sustainable earnings. Moreover, the initial small-scale development, once proven effective, will often become the first phase in the development of further “cookie-cutter” phases, and initial production from that first phase can be used to fund further expansion.

In-Situ Technologies

Currently, surface mining accounts for 55% and in-situ for 45% of oil sands production. However, in-situ production is expected to surpass surface mining production by 2016 as 80 per cent of total reserves, 135 billion barrels, are only recoverable through in-situ technologies due to the depths of the oil sands deposits and the costly process of removing overburden. This fact, combined with the high operating costs inherent in traditional extraction methods and increasing pressure from environmental stakeholders concerned with the size of the mining “footprint”, provide continued incentive for significant investment in technological advancement.

In-Situ technologies currently in use include SAGD and Cyclic Steam Simulation (CSS), but research is underway for further, potentially more cost-effective and less environmentally intrusive, in-situ technologies. One such technology is vapour extraction (VAPEX) which, in place of steam, uses hydrocarbon solvents to dilute the bitumen in place, allowing the bitumen to release from the oil sands and to flow more easily for extraction at lower heat and thus with lesser energy input. Petrobank Energy and Resources Ltd. is currently testing a form of in situ combustion known as “toe to heel air injection” (THAI) at its Whitesands project. A small company, Excelsior Energy Limited, is developing a similar in-situ method called “combustion overhead gravity drainage” (COGD) which it claims will recover twice the oil with only 20 percent of the energy input necessary for traditional SAGD. EnCana Corporation’s spinoff Cenovus plans to test a solvent-assisted steam process at Narrows Lake, its new oil sands project, that it says could cut greenhouse gas emissions by 25 to 30 %, and IOL has been testing a similar technology.

Upgrading

The major oil companies operating in Alberta’s oil sands have a current upgrading capacity slightly in excess of 1 million bpd, the vast majority being in the Athabasca region. This includes Suncor’s facilities (440,000 bpd), Syncrude’s Mildred Lake upgrader (407,000 bpd), CNRL’s Horizon upgrader (110,000 bpd), and Nexen Inc.’s Long Lake upgrader (72,000 bpd).

The Athabasca Oil Sands Project’s Scotford Upgrader 1, a joint venture among Shell Canada, Chevron Corporation and Marathon Oil Corporation producing 155,000 bpd, remains the only operating upgrader in Edmonton’s Industrial Heartland region, a region slated for multiple developments, and frequently cited as ‘Upgrader Alley’.

Value Creation Inc.’s subsidiary BA Energy has obtained approval for its Heartland Upgrader. While currently awaiting funding, the project is approved to add to the Industrial Heartland an additional merchant upgrading capacity of 260,000 bpd in 3 phases.

CNRL and North West Upgrading Inc. have formed a 50/50 joint venture to develop a $4-billion upgrader refinery in Edmonton’s Industrial Heartland. The Alberta Government has chosen this project as a preferred proponent to enter into negotiations for use of this upgrading facility for its bitumen royalties in kind (BRIK) production. Site preparation for phase 1 of this project (50,000 bpd) is complete, and pending a successful outcome of negotiations with the Province, start-up is planned for 2013.

Total E&P Canada (a subsidiary of the French multi-national) has also recently stated an intention to revive its plans to construct an upgrader in the Edmonton area. Commissioning of Phase 1, planned to produce 152,000 bpd is expected in 2013/2014. Phase 2, for which the timeline is yet to be determined, is expected to bring total capacity up to 235,000 bpd.

Suncor has yet to issue a timeline or statement of intentions with respect to the previously approved Fort Hills Upgrader (340,000 bpd) in the Industrial Heartland, which it acquired as part of the Petro-Canada merger. The Fort Hills project is led by Suncor with each of Teck Resources Limited and Total holding a 20% interest. Suncor’s suspended Voyageur Upgrader to be built in the Athabasca region (234,000 bpd). Suncor has stated that decisions with respect to these projects are not anticipated until late 2010.

Pipelines

If bitumen production in Alberta rises rapidly to over 3 million bpd by 2020, and upgrading capacity does not keep pace, excess bitumen production will be shipped south of the border or elsewhere for upgrading and refining. Further oil sands development will require the development of pipeline (or other transportation) infrasctructure to the American market, and both pipeline companies and American refineries are preparing for this. From Detroit (Marathon), to Ohio (BP/Husky), to Illinois (ConocoPhillips and Encana), to Texas (Shell and Valero) and Louisiana (Marathon), refineries throughout the US are gearing up to receive Alberta’s bitumen.

Enbridge Inc. (Enbridge) and TransCanada Corporation (TransCanada), Canada’s largest pipeline companies, are both in the process of constructing export pipelines to the American Midwest. Enbridge’s 1,607km Alberta Clipper pipeline, running from Hardisty, Alberta (just southeast of Edmonton) to Superior, Wisconsin, is expected to be in service later this year. Initial capacity will be 450,000 bpd, but Enbridge is planning for an ultimate capacity of up to 800,000 bpd. This will be in addition to the Enbridge’s Southern Access Expansion already partly in operation.

TransCanada’s 3,456 km Keystone Pipeline, running from Hardisty to Wood River and Patoka, Illinois, and on to Cushing, Oklahoma, is currently entering service to the American Midwest and capacity is expected to ramp up to 590,000 bpd by year end. Regulatory proceedings are already under way for an expansion to the Keystone system which would add another 500,000 bpd of capacity from Hardisty through Cushing to the Gulf Coast by sometime in 2012. Kinder Morgan Energy Partners (Kinder Morgan) and Altex Energy Inc. (in partnership with Canadian National Railway Company) have also announced intentions to develop pipeline capacity from Alberta to the Gulf Coast.

Shipping bitumen product via pipeline requires large amounts of diluent to dilute the bitumen and decrease its viscosity. In response to this demand, Enbridge is constructing the 180,000 bpd Southern Lights Diluent Pipeline to bring light diluting hydrocarbons from the Chicago area to Alberta’s oil sands. This project is currently under construction and is expected to be in operation by the end of the year.

Currently, the only pipeline access to the west coast is the 300,000 bpd capacity of Kinder Morgan’s Trans Mountain Pipeline from Edmonton to the Vancouver area. Another option under consideration is Enbridge’s proposed 1,170 km Northern Gateway Pipeline, which would run from Edmonton to a marine terminal in Kitimat, British Columbia. This proposal is currently under regulatory review and has encountered some opposition from aboriginal groups. Subject to regulatory approval, Enbridge plans to begin construction in 2012 and operation in 2015. The project would include 2 lines, one with a capacity to ship 525,000 bpd of diluted bitumen to the West Coast, and a parallel line running east to Alberta with a capacity to ship 193,000 bpd of condensate (diluent) to be used to thin bitumen for return pipeline transport. Further and better access to the Pacific Coast would provide oil sands producers with more flexibility to market their product and would open up East Asia, particularly China and Korea, as a viable export market.

Oil Sands Projects Updates

  1. Suncor Energy Inc.

The merger of Petro-Canada and Suncor, completed on August 1, 2009, created Canada’s largest energy company and the fifth largest in North America based on market value. The merged company’s growth projects in the oil sands were put on hold for most of 2009, awaiting a determination of which projects provided the most promising rates of return, near-term cash flow and lowest risk profile. The company expected that efficiencies resulting from the merger would reduce annual capital spending by $1 billion, and would result in savings of $300 million annually in operational expenditures.

Oil sands production was down significantly in Q1 of this year to an average of 202,300 bpd, compared to an average of 278,000 bpd in the same quarter a year ago, but has since rebounded and reported an average production of 333,000 bpd for the month of April. Decreased production was caused by unplanned maintenance following two unrelated fires at Suncor’s upgraders. Suncor has since announced an intention to direct $1.5 billion in 2010 to growth projects primarily in the oil sands. The majority of funding will be directed toward completion of its Firebag Stages 3 and 4 in-situ projects, with first production expected at Firebag 3 in Q2 2011 and ultimately a total production capacity of 68,000 bpd. Firebag Stage 4 will have equivalent capacity and first production is expected in Q4 2012. Plans for further growth projects approved or under regulatory review, including Firebag Stages 5 and 6 (62,500 bpd each), Voyageur South (120,000 bpd) MacKay River expansion (40,000), Lewis Phases 1 and 2 (40,000 bpd each), Meadow Creek Phases 1 and 2 (40,000 bpd each) and Suncor’s 60% interest in Fort Hills (a mining project to produce 165,000 bpd), are not expected to be prioritized (and made) until Q4 2010.

  1. Syncrude Canada Ltd.

Syncrude’s mining operations at Mildred Lake and Aurora, collectively the largest oil sands mining project in Northern Alberta, is a joint venture between Canadian Oil Sands Limited (36.74%); IOL (25%); Suncor (12%); Sinopec (9.03%); Nexen Oil Sands Partnership (7.23%); Mocal Energy Limited (5%); and Murphy Oil Company Ltd. (5%). The current production capacity of Syncrude’s mining project is 407,000 bpd. Actual average production during Q1 2010 was 269,000 bpd, down 5,000 bpd from the same quarter a year ago due to turnaround and unplanned maintenance.

  1. Shell Canada / Chevron Corporation / Marathon Oil Corporation

The joint venture among Shell (60%), Chevron (20%), and Marathon (20%), known as the Athabasca Oil Sands Project (AOSP), continues to produce at its “name-plate” capacity of 155,000 bpd at its Muskeg River mining facilities and the Shell Scotford Upgrader. The 100,000 bpd Jackpine mining project is near completion and is scheduled to begin ramping up production in the second half of 2010. The AOSP has approvals in place for a further 215,000 bpd, but Shell has announced its intention to focus on growth projects outside the oil sands for the time being and suggests it will wait at least 5 years before sanctioning any further expansion. Shell has also submitted an environmental impact assessment for expansion of its Carmon Creek in-situ project at Peace River which would take its current production capacity of 12,501 bpd up to 92,501 in two 40,000 bpd expansion phases.

  1. Canadian Natural Resources Limited

“First Synthetic Oil” at Horizon was produced on February 28, 2009 and the first shipment of light synthetic crude to the sales pipeline commenced on March 18. Ramp-up has been slower than CNRL anticipated, but continues towards Phase 1’s production capacity of 110,000 bpd and is expected to be sustainable at or near capacity by mid-2010. Engineering and procurement continue for approved expansion (debottlenecking) to 120,000-140,000 bpd, but sanction of Tranche 2 and 3 (to bring production to 180,000 bpd) is not expected before the end of this year. In-situ projects on the drawing board in the Athabasca region total a potential of 255,000 bpd. Regulatory approval of the Kirby in-situ project (45,000 bpd) is expected soon, and sanctioning of the project is expected later this year. CNRL’s CSS projects at Primrose / Wolf Lake in the Cold Lake region continue to operate, although slightly below current production capacity of 120,000 bpd.

  1. Nexen Inc. / OPTI Energy Inc.

Production at Phase 1 of the Long Lake SAGD project (capacity of 72,000 bpd) has risen from an average of 14,000 bpd in Q4 2009 to a reported 25,000 bpd in April of this year. All regulatory approvals are in place for Phase 2, however sanction for Phase 2 has been deferred, presumably until Phase 1 of production begins to approach project capacity. After purchasing a 15% interest in the Long Lake Project from OPTI Canada Inc. (OPTI) for $735 million, Nexen now holds a 65% interest in the project and is operator of both the Long Lake upgrader and the Long Lake SAGD Project. Phase 1 of the upgrader is now also fully operational (with a capacity of 72,000 bpd). Syngas, a by-product from the upgrader, is being used to heat water and produce steam for SAGD operations, which will significantly reduce the need for purchased natural gas.

  1. Imperial Oil Limited

Phase 1 of the Kearl Lake mining project is currently under construction with approximately 2,000 workers engaged on site. Production is expected to start up in late 2012. Phase 1 is expected to produce approximately 110,000 bpd of bitumen. Phases 2 and 3 have received regulatory approval and are expected to increase total production to 300,000 bpd, but no decision has been made as to when these phases will proceed. No upgrader is planned to process the bitumen. IOL’s in-situ operations in Cold Lake (140,000 bpd) continue to operate, and an initiative to incrementally increase production by a further 30,000 bpd has been approved.

  1. Total E&P Canada Ltd.

Total and ConocoPhillips (a 50/50 joint venture) announced early in the year that they planned to quadruple oil sands production at their Surmont lease from 27,000 to 110,000 bpd by 2015, with construction to begin later this year. Total’s Joslyn North (formerly Deer Creek) mining project (100,000 bpd) is currently in the regulatory approval process. No announcement has been made regarding projected sanctioning of the project. Total has confirmed that it will not be proceeding with development of the in-situ portion of the Joslyn project. Regulatory application for the Northern Lights mining project (a 50/50 joint venture of Total and Sinopec) has been withdrawn and Total is currently reconsidering the timeline for project development. Total has however restated its ambition to be producing hydrocarbons totalling 250,000 bpd in Canada by 2020.

  1. Cenovus Energy Inc. / ConocoPhillips Canada

Cenovus, which was split-off from EnCana in 2009, plans to spend $2-2.3 billion US to further develop and operate the Christina Lake and Foster Creek in-situ projects, and to expand the Wood River refinery in Illinois where some of its Athabasca bitumen is processed (the entire initiative is owned 50/50 with ConocoPhillips). At Christina Lake, construction of Phase 1C continues and is expected to begin production in late 2011, adding another 40,000 bpd of production capacity to the current 18,800 bpd. Construction of Phase 1D, of similar size, is now expected to begin production in 2013. At Foster Creek, as of the end of 2009 Phases 1D and 1E were both in operation, bringing total production capacity to 120,000 bpd. Regulatory applications for Phases 1F, 1G and 1H have been filed for a further 90,000 bpd of potential capacity. Cenovus is also expected to file an application for regulatory approval of its Narrows Lake in situ project which is anticipating a production capacity of up to 120,000 bpd, to be developed in as many as three phases.

  1. Husky Energy Inc./ BP Plc

Construction on the Sunrise SAGD project, a joint venture between Husky and BP, is expected to begin in the second half of 2010. All regulatory approvals are in place, and all front-end engineering has been completed for Phase 1 of the project. New cost estimates for the first phase of the project are now estimated to be $2.5 billion, down from an original $4.5 billion estimate. The first phase is expected to produce approximately 60,000 bpd, with first production expected in 2014. Husky expects to make a final sanctioning decision by year end. Total production for the entire project as planned is an ultimate 200,000 bpd. Husky and BP intend to refine bitumen produced from their Sunrise project at a jointly owned refinery outside of Toledo, Ohio. Production continues at Husky’s Tucker in-situ project (30,000 bpd) in the Cold Lake region.

  1. Devon Energy Corporation

Devon’s Jackfish 1 SAGD project (35,000 bpd) has been in operation since late 2007 and is producing at near capacity as of late 2009. Construction of Jackfish 2 (also 35,000 bpd) began in 2008. The first producing wells in the second phase were drilled in July 2009, but full start up is scheduled for 2011. Regulatory approval for Jackfish 3 is anticipated for late 2010 and construction is scheduled to begin in 2012 with first production expected in 2014.

Conclusions

More active development and exploitation of Alberta’s oil sands reserves is seemingly inevitable as evidenced by the resurgence in investment in recent months from domestic and foreign players alike. While the economic costs associated with the development of this resource are certainly greater than for more conventional oil, the oil sands provide a substantial and accessible source of energy in a stable and supportive political environment. Continued technological innovation, particularly for in-situ projects, and continued growth in access to export markets through the further development of pipeline infrastructure will help ensure that development and production continues on a predicted trajectory toward 3.5 million bpd by 2025.

Certain information for this article was taken from Oilsands Review: The Unconventional Oil Authority