Oil Sands Operators Weather the Perfect Storm
A production limit mandated by the Albertan government is just one of the difficulties facing oil sands producers this year.

By Carly Leonida, European Editor

A handful of bitumen ore. (Photo: Suncor Energy Inc.)
Oil sands producers have faced more than their fair share of challenges in recent years. Despite battling wildfires, pipeline disputes and tough environmental regulations, the sector pumped almost C$13 billion (US$9.7 billion) into the Canadian economy last year, with roughly the same expected for 2019. However, with political tensions running high and a 12-month limit on production levels in place, 2019 may prove their toughest year yet.

Canada is the world’s fifth biggest oil producer, boasting the third-largest proven reserve (Saudi Arabia and Venezuela hold the top two spots) at 171 billion barrels (bbl). The vast majority of this, around 97%, is locked up in oil sands — a naturally occurring mixture of water and bitumen plus sand, clay and other minerals — that can be surface mined or extracted using in-situ techniques such as steam-assisted gravity drainage (SAGD) depending on the depth of the deposit.

Canada’s most significant deposits — Athabasca, Peace River and Cold Lake — stretch across Alberta and into Saskatchewan. The vast majority of oil sands operations are located in Alberta, and these are primarily developed by the private sector with investment from companies based in Canada, the U.S., Europe and Asia. As a result, the economic impact of decisions that affect oil sands developments reach right across the globe.

The government of Alberta estimates that over the next 20 years, the oil sands industry will pay C$1.7 trillion in provincial and federal taxes, including royalties. However, competition for capital investment in the oil and gas market is tough, and a recent report from the Canadian Association of Petroleum Producers (CAPP) on the sector’s competitiveness estimates that capital investment in Canada’s oil and natural gas industry has declined 50% since 2014, from C$80 billion dollars in 2014 to C$40 billion dollars in 2018.

With a mandated bitumen production limit currently in place in Alberta, and decisions expected in the coming weeks over some rather questionable federal bills, the fate of some important projects hangs in the balance. Let’s take a look at the challenges and how some key players are faring.

Imperial Feels the Cold
2019 began as it meant to go on, and the weather proved a big challenge for many oil producers. Alberta faced one of the coldest February’s on record thanks to a polar vortex that drew down cold air from the Arctic. Temperatures in Edmonton dipped below -26°F and the cold snap lasted well into March, thwarting many miners attempts to reach their production targets. Imperial Oil, which is majority owned by Exxon Mobil, published its 2019 first-quarter interim report in May, detailing a net income of C$293 million (down significantly from the C$516 million earned during the same period in 2018) with C$1 billion in cash generated from its operations.

“First-quarter operational performance was impacted by challenges in both the upstream and downstream early in the quarter, in part due to extreme cold weather across the country,” said Rich Kruger, Imperial’s chairman, president and CEO. “Furthermore, the government of Alberta’s production-curtailment order significantly affected financial performance, as improved upstream realizations were more than offset by reduced downstream margins.” Gross production of bitumen at Imperial’s Cold Lake in-situ operation in northeastern Alberta averaged 145,000 barrels per day (bbl/d), compared to 153,000 bbl/d in the same period of 2018 thanks to the weather that hampered production timing and steam management.

Despite the cold weather, work at Imperial’s Kearl operation soldiered on. Located 70 km north of Fort McMurray, the operation has an estimated 4.6 billion barrels of recoverable bitumen, which is expected to support production for the next 40 years. Production at Kearl’s initial development began in April 2013, while an expansion project in mid-2015 brought production capacity to 220,000 bbl/d. According to Imperial, Kearl averaged 180,000 bbl/d in the first quarter (not quite the 200,000 bbl/d it is capable of), and the company confirmed that a C$550 million debottlenecking project that began in 2018 is on track for completion at the end of the year. The project will increase Kearl’s production capacity by 20,000 bbl/d, to a total of 240,000 bbl/d, and will add additional crushing capacity to create an offset when plant equipment is undergoing maintenance.

The Fort Hills ore preparation plant accepts raw bitumen and prepares it for further processing.
Shown here are the sizer conveyors and surge bin. (Photo: Suncor Energy Inc.)
Kearl’s autonomous haul truck program also received regulatory approval from Alberta Occupational Health and Safety, granting Imperial the ability to automate its entire fleet. Plans include expanding the scope of the ongoing pilot program from seven to 20 Cat 797F trucks through 2020, before the company makes a final decision on full automation. Imperial said the project is expected to drive “a significant improvement in safety performance and operating cost.” One area in which Imperial did not hold back was investment for sustainability initiatives. The company donated C$1 million in the first quarter to help develop a two-year water management program at the Southern Alberta Institute of Technology (SAIT); purportedly the first of its kind in Canada.

The company has also been working on reducing its energy consumption and has invested C$2.1 billion over the past 20 years on R&D for new technologies. Between 2013 and 2017, Imperial managed to reduce the intensity of greenhouse gas emissions from its operated oil sands by 20%, and it plans to cut levels by a further 10% over the next five years. Imperial added that it is developing new technologies that could reduce greenhouse gas emissions intensity for future in-situ oil sands production by approximately 25% to 90%.

Production Curtailed
Another thorn currently in Imperial’s side, and that of other oil sands producers, is the mandated production curtailment announced in December 2018 by then Albertan Premier Rachel Notely. The temporary measure was put in place from January to counteract a historically high oil price differential that Scotiabank estimated was costing the national economy more than C$80 million per day, and it is expected to last until the end of 2019.

In late 2018, Alberta was producing 190,000 bbl/d of raw crude and bitumen more than could be carried by pipelines and rail, which resulted in a significant surplus at storage facilities. In total, around 35 million barrels of oil were in storage (twice the normal amount), which meant that facilities were approaching capacity. Under the action, production of raw crude oil and bitumen was to be reduced by 8.7% or 325,000 bbl/d to reduce the glut, and production limits are gradually being lifted each month to around 95,000 bbl/d, which will be maintained until December 31, when the rules will be lifted.

Alberta’s natural resources belong to Albertans, and in exchange for the right to develop these resources, companies pay the government a royalty. This is a percentage of revenues generated from the sale of oil and natural gas products or, in some cases, takes the product inkind for the government to sell. In late 2018, the price differential for Western Canadian Select (WCS) versus West Texas Intermediate (WTI) was hovering around US$30 to US$50, peaking at US$52 in October. The curtailment is designed to reduce volatility, narrowing the price differential by at least US$4 per barrel relative to where it otherwise would have been, adding C$1.1 billion of government revenue in 2019-2020 — money that Notely said will be used to pay for roads, schools and hospitals.

“Every Albertan owns the energy resources in the ground, and we have a duty to defend those resources,” she said in December. “But right now, they’re being sold for pennies on the dollar. We must act immediately, and we must do it together. I can’t promise the coming weeks and months will be easy, but I can promise we will never back down in our fight to protect jobs and the resources owned by all Albertans.” Whether producers like prices being manipulated or not, the curtailment is working. By the end of the first quarter, WTI had averaged US$54.90 per barrel and WCS US$42.44 narrowing the differential to around US$12.

Imperial for one is not a fan. After increasing crude-by-rail shipments to record levels in late 2018, the company discontinued shipments in February before resuming them late in the quarter. “[We] will continue to evaluate future movements as economically justified,” Kruger commented. The company also announced a slowdown in the development of its Aspen in-situ mining project, which it said was a direct result of “market uncertainty stemming from the government of Alberta’s intervention in crude markets and other ‘industry competitiveness challenges.’”

“Imperial’s view remains that free markets work, and intervention sends a negative message to investors about doing business in Alberta and Canada,” the company said in a press release announcing the changes at Aspen in March. “The company remains concerned about the unintended consequences of the government’s decision to manipulate prices, including the negative impact on rail economics.” Imperial sanctioned development of the C$2.6 billion Aspen project in November 2018, prior to the curtailment policy’s announcement and implementation. The project is expected to employ 700 people during construction, create 200 permanent jobs and produce 75,000 bbl/d of oil. Based on preliminary estimates and tax and royalty rates at the time of the halt, Imperial said the project could deliver more than C$4 billion in direct federal and provincial tax revenues and C$10 billion in royalties for Alberta over its projected life. The slowdown in project execution is expected to delay delivery by at least a year.

“This was a difficult choice in light of our final investment decision on Aspen,” said Kruger. “However, we cannot invest billions of dollars on behalf of our shareholders given the uncertainty in the current business environment. That said, our goal is to ensure the work we do this year will enable us to effectively and efficiently resume planned activity levels when the time is right.”

Fort Hills Forges Ahead
Suncor meanwhile got creative with its first quarter production strategy and allocated a portion of its mandated bitumen limit to Syncrude to help boost its upgrader utilization to 90% compared to 71% in the previous year quarter. Suncor is Syncrude’s majority owner and the company increased its shares in February 2018 by 5% to 58.74%. The remaining shares are held by Imperial, CNOOC Oil Sands Canada and Sinopec.

Suncor recorded 657,200 bbl/d of oil sands production in the first quarter of 2019 compared to 571,700 bbl/d in the prior-year quarter. The company said increased production from the ramp up at Fort Hills and improved Syncrude asset utilization more than offset the impact of mandatory production curtailments. “Suncor’s integrated model has consistently generated positive results through changing market conditions, including mandatory production curtailments in Alberta, and the first quarter of 2019 was no different,” said Mark Little, president and chief operating officer, in Suncor’s first-quarter report. “Funds from operations increased to C$2.6 billion in the first quarter of 2019 as we continue to execute on our long-term strategy.”

A hydraulic shovel places overburden in a haul truck at the Fort Hills site.
(Photo: Suncor Energy Inc.)
Suncor is also the majority owner of the Fort Hills project with a 54% share, with the remaining shares split between Total (24.5%) and Teck (21.31%). The mine has two open pits and a fleet capable of producing 14,500t/h, or 194,000 bbl/d, of oil sand at full capacity. Fort Hills began production in January 2018, achieving commercial levels in June last year and, according to Teck’s 2019 first-quarter report, the operation has performed well during startup and commissioning. The project was delivered just four weeks after its projected date and, given the delays resulting from severe wildfires in Fort McMurray during construction, this was no mean feat.

Teck said there is also further potential to de-bottleneck and expand production capacity. “Evaluation of de-bottlenecking opportunities will include near-term work with minimal to no capital. Long-term opportunities that may require modest capital expenditure will also be investigated. Between the near-term and long-term opportunities, there is the potential to increase Fort Hills’ production by 20,000 to 40,000 bbl/d of bitumen on a 100% basis over the medium-term. Our share of annual bitumen production could increase from 14 million barrels to approximately 15.5- 17 million barrels,” the company said.

The regulatory application review of Teck’s Frontier project also continued with a public hearing before a joint federal/ provincial panel that concluded in December 2018. Frontier is a proposed 260,000-bbl/d truck-and-shovel operation located between Fort McMurray and Fort Chipewyan in northeast Alberta. The project is currently advancing through a joint federal-provincial regulatory review process, and Teck said the earliest a decision statement could be expected is the first quarter of 2020.

“Our expenditures on Frontier are limited to supporting this process,” the company said in its report. “We continue to evaluate the future project schedule and development options as part of our ongoing capital review and prioritization process.

CNRL Rebuilds Scotford
Canadian Natural Resources (CNRL) is also a supporter of the mandatory production curtailments. The company voluntarily curtailed its heavy crude oil production in the fourth quarter of 2018 by 9,600 bbl/d, and its first-quarter 2019 results saw production decrease a further 14% to 68,473 bbl/d. In total, CNRL’s oil sands operations produced 416,206 bbl/d of synthetic crude oil (SCO) in the first quarter, a decrease of 7% from 2018 Q4 levels thanks to the curtailment and increased maintenance activity. However, as a result of market adjustment, the company’s net earnings were up significantly at around C$1 billion.

Commenting on the company’s first-quarter 2019 results, Steve Laut, executive vice chairman, stated: “The company demonstrated the resilience and strength of its long-life, low-decline and low-capital exposure assets, generating significant adjusted funds flow of approximately C$2.2 billion. “The company was able to achieve adjusted funds flow that exceeded net capital expenditures by approximately C$1.3 billion, largely due to a strong operational quarter and improvement in crude oil differentials, driven by the government of Alberta’s mandatory production curtailments, which is strongly supported by Canadian Natural.”

CNRL President Tim McKay added: “Operations were strong in the first quarter as our large, balanced and diverse asset base allowed the company to strategically manage through the mandatory production curtailments to maximize value. Production was as expected in Q1/19, reaching approximately 1,035,000 barrels of oil equivalent per day (BOE/d), consisting of 54% light crude oil, NGLs and SCO, 22% heavy crude oil and 24% natural gas.” CNRL faced another challenge during April in the form of a fire at the Scotford upgrader in which it has a 70% interest. The fire was contained to a process furnace in the North Upgrader, while operations at the South Upgrader plant were not impacted.

The planned 38-day repair program was forecast to cost C$15 million, and CNRL optimized its other Albertan assets to mitigate the financial impact. Work began on April 14, and until the program was complete, the South Upgrader ran at a restricted net processing rate of 140,000 bbl/d of SCO. The maintenance finished in June and CNRL said May and June net production at its Albian mines averaged 171,500 bbl/d, rather than the planned 178,500 bbl/d.

Kirby North: On Budget and Ahead of Schedule
CNRL has also been busy at its Primrose and Kirby in-situ facilities. Work to install additional pads at Primrose is on budget and ahead of schedule with initial production targeted in late 2019. CNRL expects the program to deliver an extra 26,000 bbl/d in the first 12 months of production. “These pad additions are high-return activities as the company utilizes available excess oil processing and steam capacity at Primrose,” the company stated in its report.

Work at the new Kirby North SAGD operation continues to push ahead, and this has resulted in the project progressing two quarters ahead of schedule with overall cost performance remaining on budget. Commissioning of the central processing facility took place on May 1, and CNRL plans to progressively ramp up production toward Kirby North’s overall capacity of 40,000 bbl/d, in late 2020. Construction originally began at Kirby North in 2014, but was halted less than a year later due to a drop in oil prices. Most of the major equipment had been purchased by that point and, after a bit of careful budgeting, CNRL resumed work in late 2017 with well-pair drilling taking place throughout 2018. The company will no doubt be pleased to see the mine operational.

Like Imperial, CNRL is also dedicating significant resources to environmental initiatives. The company has invested more than $3.4 billion in R&D since 2009 and stated in its Q1 2019 report that by leveraging technology, including carbon capture, it has developed a pathway to reduce its greenhouse gas emissions intensity to below the average for global crude oils. As part of this, CNRL is currently running an In-Pit Extraction Process (IPEP) pilot at its Horizon operation that will determine the feasibility of producing stackable dry tailings. The initial testing phase has now concluded, and CNRL said that “results have been positive with excellent recovery rates and evidence of stackable tailings. The company continues to make enhancements and will operate and test the pilot through 2019.”

CNRL added that the project has the potential to reduce its carbon emissions and environmental footprint by reducing the usage of haul trucks, the size and need for tailings ponds and accelerating site reclamation. In addition, the process has the potential to significantly reduce capital and operating costs.

Kenney Wages War
Restricted market access was an issue that all the producers above mentioned in conjunction with their first-quarter 2019 results, either on paper or during investor/ analyst calls. The topic is unavoidable, as pipeline bottlenecks were a key cause of the Albertan production curtailment. Jason Kenney, who succeeded Notely to become Alberta’s 18th premier on April 30, has been very vocal in his support for better transportation infrastructure and he has, on a number of occasions, voiced concerns about the impact of this issue on the competitiveness of Canada’s oil and gas producers.

One of Kenney’s first speeches was delivered to the Canadian government’s Transportation and Communications Senate Committee just hours after taking office, in which he called for Bill C-48, which seeks to ban Canadian oil tankers off much of Canada’s west coast, to be scrapped. “This bill has been referred to as an oil tanker ban on Canada’s northern west coast. It’s actually a ban against oil only from Alberta,” he said. “For example, Canada cannot stop foreign oil tankers passing through the same waters in which Alberta oil is banned. Loaded foreign oil tankers will continue to travel the British Columbia coast between Alaska and Washington. The result is two sets of laws here — one for Alberta oil, another for foreign oil.”

His speech had the desired effect and the bill was voted down on May 16. The move was praised by many, including the CAPP, which estimates that lack of market access currently costs Canadian producers between C$10.8 billion and C$15.6 billion annually. The CAPP represents around 80% of Canada’s oil and natural gas producers and is widely considered the voice of Canada’s upstream oil, oil sands and natural gas industry.

“There is no rationale for the government to proceed with Bill C-48,” commented Tim McMillan, CAPP’s president and CEO. “It would permanently take away Canada’s opportunity to move our energy products to growing international markets in Asia. Tankers have safely been travelling in waters off the west coast for decades.” Between 2014 and 2017, the number of people employed in exploration and production, oil and natural gas, and oil sands construction fell by about 60,000 people across the country. The CAPP strongly believes that Bill C-48 puts additional jobs, businesses, and communities at risk by putting a barrier in the way of healthy economies.

No More Pipelines?
Not content with waging war on just one front, Kenney also took the Senate Committee on Energy, the Environment and Natural Resources, to task on May 2, over C-69 — the No More Pipelines bill. Pipeline bottlenecks and construction delays are a long running theme in the oil sands. The price gap that resulted in this year’s production curtailment has been widely attributed to the Canadian federal government’s decades-long reluctance to increase pipeline capacity, and this has left Alberta’s energy producers with few options to move their products to market.

A case in point is the Trans Mountain pipeline expansion project; this is essentially a twinning of the existing 1,150-km (715 mile) pipeline between Strathcona County near Edmonton in Alberta, and Burnaby in British Columbia. The proposed expansion will boost the capacity of the system from 300,000 bbl/d to 890,000 bbl/d and create hundreds of new jobs. However, despite receiving the go ahead from the federal government in 2016, construction on the project was brought to a halt in mid-2018 pending a reconsideration report by the National Energy Board.

The report, which recommended the project proceeds, was delivered to the federal government in February, President Justin Trudeau once again approved the expansion on June 18. However, this is the third time the project has been approved. It still requires a Certificate of Public Convenience and Necessity from the NEB and the pipeline must be built in accordance with 156 conditions stipulated also by the NEB. In short, if the pipeline is built, the path forward is unlikely to be smooth.

Either way, investor confidence in the project has been severely shaken. And this is just one of a number of pipeline projects currently being held up for complex political reasons — Google Keystone XL if you have a few hours to spare. Kenney told the senate committee: “Already, Canada’s resource sector is increasingly seen by investors as not worth the risk — and we’ve all been paying the price in billions of dollars in lost economic potential. We’ve seen that with Kinder Morgan walking away from the Trans Mountain pipeline and TransCanada giving up on Energy East — both because of increasing delays and growing regulatory uncertainty.

“Canada’s resource sector has seen an alarming number of projects either put on hold or shelved completely in favor of more welcoming jurisdictions like the United States. And now, looming over the horizon is the dark cloud of Bill C-69. “It will further erode confidence in Canada’s regulatory framework and deter investment in a country already seen as too risky a place to invest. In 2017 and 2018, for example, the planned investment value of major resource sector projects dropped by C$100 billion. We know oil prices aren’t the culprit, especially when we see how well the energy sector is doing south of the border.”

Kenney also pointed out that Bill C-69 also gave federal agencies the power to regulate provincial projects, such as in-situ oil sands developments and petrochemical refineries, which are entirely within a province’s borders and already subject to provincial regulation. “The threat posed by Bill C-69 cannot be dismissed as a uniquely Alberta issue. When Alberta’s energy sector suffers, it cascades through the whole provincial economy, and then ripples out across our national economy,” he said.

Kenney met with a number of senators in May to discuss both Bill C-48 and C-69, and also enlisted Energy Minister Sonya Savage to help fight his corner. He delivered a letter to all senators co-signed by the leaders of Alberta’s official opposition and the two other major provincial parties, urging that the senate respect the will of its committees by rejecting Bill C-48 in its entirety and accepting recommended amendments to Bill C-69. However, despite Kenney’s best efforts, the federal government voted to pass both Bills C-48 and C-69 on June 20. “Bill C-48 is a prejudicial attack on Alberta, banning from Canada’s northwest coast only one product — bitumen — produced in only one province, Alberta. After thousands of hours of study, the Senate transport committee determined that there was no defensible rationale for this bill,” he said in a terse statement issued shortly after the announcement.

“Bill C-69, the ‘No More Pipelines Law,’ has been adopted with virtually none of the amendments proposed by the government of Alberta, or industry groups. The Senate had commendably made 188 constructive amendments to the bill, which were subsequently stripped out by the Trudeau government in the House of Commons. The bill, in its final form, is opposed by nine of 10 provinces, almost every major industry group in Canada, and dozens of First Nations.

“It inserts massive new uncertainty into the federal environmental approval process for major projects, leading energy industry groups to say that no future pipeline will ever be proposed under this regime. It is also a flagrant violation of the exclusive constitutional jurisdiction of provinces to control the development of their natural resources.” Kenney has vowed to challenge the passage of both bills in court, but whether the Trudeau government listens will be another matter. One thing is certain: 2020 will not prove any easier for Alberta’s oil sands producers.

As featured in Womp 2019 Vol 07 - www.womp-int.com