Status report: slow starts and further delays for N.L. offshore in 2021-22

Posted on March 10, 2021 | Atlantic Business Magazine | 0 Comments

Searose FPSO and offshore support vessels (August, 2005).
Creative Commons

As the promise of government relief funds begin to flow, the perils of the pandemic continue to plague Newfoundland and Labrador’s offshore oil and gas industry. Though oil production continues at Hibernia, Hebron and the SeaRose Floating Production Storage and Offloading Vessel (FPSO), the Terra Nova FPSO has not produced oil in over a year.

The oil and gas industry is accustomed to handling rapid change at a global-scale, with oil prices influenced by everything from politics to production and demand to the quality of crude oil. But the magnitude of the COVID-19 crisis is incomparable to anything the industry has weathered, creating a slump in the demand for crude oil. That lull continues, as the world hunkers down for the latest round of pandemic lockdowns.

Historic glut
As oil prices fell dramatically at the outset of the pandemic, the industry stalled exploration, halted drilling, abandoned construction and laid off workers. But Jim Keating, the acting CEO of OilCo, the provincial crown corporation formed in January of last year to manage N.L.’s interests in the offshore, thinks hope may be on the horizon.

“By most accounts, we’re already seeing a return to the price level,” says Keating. In mid-January 2021, Brent crude oil had reached about $58 U.S. per barrel. While that’s shy of the $73 per barrel reported in February last year, it’s nearly double last year’s lowest price. “There’s some recovery with still some room to go. But ultimately the driver for demand will be transportation, in particular air transportation. We’re starting to see in some jurisdictions, like China, as lockdowns have receded, the economy picking up quickly. In some cases, the demand for oil may actually be higher than pre-pandemic because of pent-up demand. In other words, people who now can travel really want to travel.”

In July 2020, the N.L. government reported revenue projections for 2020-21 had decreased by $631 million, primarily as a result of the unanticipated decrease in the global demand for oil. The lower price of oil, combined with the longer than anticipated shutdown of the Terra Nova FPSO, has resulted in a projected decrease of $560 million in oil revenues; and a net reduction of $71 million from all other revenue sources.

Revived demand would benefit the offshore industry and governments alike, says Paul Barnes, the Atlantic Canada and Arctic director of the Canadian Association of Petroleum Producers.
“The combination of COVID-19, the related drop in demand for oil and gas and the significant drop in oil prices in 2020, had significant and detrimental impacts on Newfoundland and Labrador’s offshore oil and gas industry. However, the market is beginning to recover, and global demand is increasing. With the right policies in place, Newfoundland and Labrador’s oil and natural gas industry can play a critical role in the province and country’s economic recovery,” says Barnes.

But even a return to pre-pandemic patterns of travel won’t solve the industry’s problems overnight. For starters, significantly reduced demand has created a global surplus of excess oil. When the pandemic hit, there was already an oversupply—for the last five years, U.S. shale oil producers had created an oil glut. That means long after quarantines are lifted, today’s historic glut will continue to affect oil markets in the months and years ahead.

Still OilCo’s Jim Keating is optimistic that the scale of the opportunity in N.L.’s offshore will continue to impress global producers. Just what is the scale? According to the Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB), the oil regulator for the province, only about nine per cent of the nearly two million square kilometres of offshore jurisdiction is currently licensed. In September 2020, OilCo announced that the province’s Independent Oil and Gas Resource Assessment shows a total of 11.1 billion barrels of oil and 24.5 trillion cubic feet of natural gas potential in N.L.’s offshore. Keating says there are at least two dozen prospects expected to offer in excess of a half-a-billion barrels, “with many in the one- to two-billion-plus barrel range, which is Hibernia and bigger.”

Exploration Work
When the pandemic hit, companies were quick to halt exploration activities (considered the highest risk capital), but a year later, there are noteworthy exploration prospects on the horizon. In mid-January, the federal government gave three off- shore exploration drilling projects the go-ahead (whether they’ll proceed remains to be seen).

BHP Petroleum (New Ventures) Corporation’s Canada Exploration Drilling Project aims to conduct an exploration drilling project in the Orphan Basin, located approximately 350 kilometres northeast of St. John’s. Equinor’s Central Ridge Exploration Drilling Project targets the Central Ridge Area, located approximately 375 kilometres east of St. John’s. And Chevron has exploration plans for the Flemish Pass, located approximately 375 kilometres northeast of St. John’s; however, a company spokesperson says, “A final decision on whether or not we’ll proceed with future drilling plans will depend on internal business decisions.”

Then there’s the China National Offshore Oil Corporation (CNOOC), which is preparing to drill the Pelles exploration well within its exploration licence in the Flemish Pass in the second quarter of 2021.

BP Canada Energy Group ULC is proposing to conduct an exploration drilling program within four exploration licences in the West and East Orphan Basins. Located between 343 and 496 kilometres offshore N.L., exploration drilling is expected to commence in 2023 pending regulatory approvals, says a spokesperson. The company was also the lone successful bidder, committing $27 million in exploration work, in the province’s latest Call For Bids as part of the Offshore Exploration Initiative. The commitment is positive news, but it’s barely a drop in the bucket compared to 2018’s successful bids for exploration rights which totaled $1.3 billion.

Meanwhile, ExxonMobil Canada recently relinquished two of its exploration licenses (in Southern Eastern Newfoundland and Jeanne d’Arc) and a spokesperson says the company “continues to evaluate its exploration licenses to determine forward plans.”

Four oil projects are in production offshore N.L. (Hibernia, Terra Nova, Hebron and White Rose), while Bay du Nord is in development. Here’s what’s happening with each of them:

Terra Nova
In May of 2019, the project operator (also its largest shareholder), Suncor, and its partners sanctioned plans to upgrade the Terra Nova FPSO, which would allow the facility to capture approximately 80 million additional barrels of oil and extend the life of the FPSO to 2031. The work had been scheduled for 2020 but was put on hold—it has not produced oil for over a year. The vessel remains out of service at Bull Arm. This is the latest in a series of debacles for the floating installation, ordered shutdown in December 2019 by C-NLOPB, which found the company failed to meet safety requirements regarding its redundant fire water pump systems.

On January 14, 2021, the NL government committed up to $175 million (as well as a modified royalty regime) as part of the Oil and Gas Recovery Assistance Fund to restart the program.
The project owners agreed to a non-binding Memorandum of Understanding with the provincial government to restart the work, but this remains to be seen.

In production since 2002, the Terra Nova FPSO was the first development in North America to use the FPSO technology in an environment with sea ice and icebergs. Project partners include: Suncor (37.675 per cent), ExxonMobil Canada Properties (19 per cent), Equinor Canada Ltd. (15 per cent), Husky Energy, a subsidiary of Cenovus Energy (13 per cent), Murphy Oil Company Ltd. (10.475 per cent), Mosbacher Operating Ltd. (3.85 per cent) and Chevron Canada Resources (one per cent).

The Terra Nova FPSO shown anchored in Conception Bay, Newfoundland and Labrador on Friday, October 23, 2020. It hasn’t been in production since December 2019. THE CANADIAN PRESS/Paul Daly

White Rose
In early December 2020, the West White Rose project became the first to receive funding from the Oil and Gas Industry Recovery Assistance Fund. The announcement of $41.5 million in funding came on the heels of news Husky assets and staff would become part of Cenovus Energy on January 1, 2021. (In December, Husky became a wholly-owned subsidiary of Cenovus Energy Inc., making the company the third largest Canadian oil and natural gas producer, the second largest Canadian-based refiner and upgrader. “It’s early days for the combined company and we’ll provide more insight on our business plans throughout the course of the year,” said a company spokesperson.)
Husky/Cenovus is the operator of the White Rose field and its satellite extensions, one of which includes West White Rose. In January 2021, the operators said production continues offshore N.L. on the Searose FPSO vessel, which is the production vessel for the White Rose field and satellite extensions, with appropriate COVID-19 mitigation measures in place. However, a company spokesperson noted, “The [Husky/Cenovus] joint venture continues to evaluate its options beyond 2021 and no decisions have been made.”

Before the consolidation in 2020, Husky Energy temporarily shut down West White Rose, then indefinitely suspended the project. The funding announced in December, which is about 50 per cent of total project costs, is intended to maintain jobs, while also restarting the West White Rose project. On deck for the restart in 2021 are such activities as: topsides fabrication, procurement, and subsea and marine operations. The project will employ a total of 331 people: 169 in project management and engineering in the province and 162 tradespersons in Argentia (on the Concrete Gravity Structure) and Marystown (work on the living quarters, flare boom, lifeboat decks, and helideck continues at the Kiewit Offshore Services Yard).

White Rose, which was first sanctioned in 2017, is located in the Jeanne d’Arc Basin. Partners include Husky/Cenovus (72.5 per cent) and Suncor (27.5 per cent), while the partners for the satellite extensions (North Amethyst, West White Rose, and South White Rose Extension) are Husky (68.875 per cent), Suncor (26.125 per cent) and OilCo (five per cent).

Bay Du Nord
“The Bay du Nord development project, a key part of Equinor’s Canadian portfolio, remains delayed. Equinor continues to work on the project and evaluate our activities in light of the economic challenges faced by the energy industry,” said a company spokesperson.

The Bay du Nord project consists of three light oil discoveries in the Flemish Pass Basin: Bay du Nord (2013), Bay de Verde (2015) and Baccalieu (2016). In early 2020, Equinor and Husky (now Husky/Cenovus) deferred the Bay du Nord development project “to make the project more robust for low commodity prices” (according to its website). Equinor’s website now indicates: “It is currently expected that an investment decision could be made in 2021, with first oil to be produced in 2025.”

Meanwhile, Norweigian-owned Equinor announced in January 2021 it was ceasing its Alberta oilsands operations (around the same time, President Joe Biden revoked the construction permit for the Keystone XL pipeline) and focusing on its offshore N.L. licenses as well as making St. John’s its Canadian headquarters. At the time, the company indicated it would be eliminating 30 per cent of its permanent staff. While the St. John’s office will see a higher number of employees, the company was planning layoffs in both its St. John’s and Calgary offices. Equinor holds 65 per cent interest in the Bay du Nord project, while Husky/Cenovus owns 35 per cent.

Bay du Nord is the first remote, deepwater project in the N.L. offshore, 500 kms from shore and approximately 1,200 metres deep. Discovered in 2013, it was expected to be sanctioned in 2020. An investment decision is still pending. GOV’T NFLD/LAB

Hebron
Despite Canada-wide job cuts announced by the project’s operator and largest shareholder, ExxonMobil Canada in 2020), as well as having halted drilling on Hibernia, the Hebron gravity-based structure (GBS) remains in steady-state production operations, reported the company in January 2021. In early September 2020, ExxonMobil announced Hebron had reached a milestone, having produced its 100-millionth barrel of oil. Located in the Jeanne d’Arc Basin, Hebron produced first oil in 2017. Its partners include: ExxonMobil Canada Properties (35.5 per cent), Chevron Canada Limited (29.6 per cent), Suncor Energy Inc. (21 per cent), Equinor Ltd. (nine per cent) and OilCo (4.9 per cent).

Like Hibernia, the Hebron field is being developed using a stand-alone concrete gravity-based structure (GBS). The Hebron GBS consists of a reinforced concrete structure designed to withstand sea ice, icebergs and meteorological and oceanographic conditions. It is designed to store approximately 1.2 million barrels of crude oil.

Hebron is the only project offshore N.L. that didn’t see a decline in operations during 2020. Shown here: the completed Hebron Oil Platform, before it was towed out to the edge of the Grand Banks off Newfoundland Canada (January, 2017). Creative Commons

Hibernia
In an effort to reduce spending in spring 2020 due to the COVID-19-induced oil price drop, Hibernia Management and Development Co. Ltd. (HMDC) halted drilling at Hibernia, resulting in layoffs. Its largest shareholder, Exxonmobil Canada, reports as of January 2021, the platform, which is located in the Jeanne d’Arc Basin, 315 km east of St John’s, is in steady-state production. On December 23, 2020, as part of the Oil and Gas Industry Recovery Assistance Fund, the province awarded $38 million in funding to Hibernia—which amounts to about 40 per cent of total project costs—to restart well work (including enabling potential future drilling), undertake drill rig updates (to reach more oil, which could allow a decade or more of future drilling), and invest in new digital technology (to support remote work and analytics, for example). The well work and rig upgrade is also expected to reduce greenhouse gas intensity. HMDC has submitted a proposal to the government for additional work, which if approved, could raise the government funding commitment to a total of $66 million. The investment will result in 77 additional, full time equivalent (FTE) positions in 2021, and maintain employment for 44 FTE positions in 2021 and 27 FTE positions in 2022, for a total commitment of 148 FTE positions.

These jobs are especially welcome news since the U.S. oil giant ExxonMobil announced in 2020 it was slashing 300 Canadian jobs, mainly in Alberta. In operation since 1997, the Hibernia platform is owned by ExxonMobil Canada (33.125 per cent), Chevron Canada Resources (26.875 per cent), Suncor (20 per cent), Canada Hibernia Holding Corporation (8.5 per cent), Murphy Oil (6.5 per cent) and Equinor Canada Ltd. (5 per cent). The partners for the Hibernia Southern Extension project, which is a subsea development with tiebacks to the platform, are ExxonMobil Canada (27.9 per cent), Chevron Canada Resources (23.7 per cent), Petro-Canada Hibernia Partnership (Suncor) (19.2 per cent), Statoil Canada Ltd. (9.3 per cent), OilCo (10.0 per cent), Canada Hibernia Holding Corporation (5.6 per cent) and Murphy Oil Company Ltd. (4.3 per cent). •

Though oil production remains ongoing, cost-cutting measures in 2020 saw unprecedented layoffs due to a halt in drilling activity at the Hibernia field. Shown here: a tug positions itself near the base of the Hibernia platform in Bull Arm, Trinity Bay, N.L., Thursday, May 22, 1997—the same year it produced first oil. THE CANADIAN PRESS/Jonathan Hayward

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