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Energy sector looking for aid and regulation delays as throne speech looms

Canada’s fossil-fuel sector is looking to this month’s throne speech for signs the federal government is not throwing in the towel on oil and gas.

At the same time Canadian climate strikers are threatening mass protests if the same speech doesn’t show a plan to eliminate all greenhouse-gas emissions produced by human activities in less than a decade.

Screen Shot 2020-06-08 at 5.12.34 PMTim McMillan, president of the Canadian Association of Petroleum Producers, says Prime Minister Justin Trudeau can use the throne speech Sept. 23 to send a signal to international investors that Canada’s oil and gas industry is a solid opportunity for investment.

He says the planned clean-fuel standard meant to force oil and gas companies to emit less greenhouse gas is out of whack with Canada’s main competitors for that investment and if the new standard isn’t postponed, many companies will simply not be able to comply.

Earlier this year Ottawa scaled back the requirements of the standard over the first few years to give companies more time to recover from the economic crisis caused by COVID-19, but McMillan says that is not enough.

Trudeau is also, however, facing pressure from thousands of Canadian youth in the Climate Strike Canada movement who say the throne speech is Trudeau’s “last chance” to convince them he really is a climate-change leader.


InvestorRelations-NewsReleases

2020’s crude price crash offers a bright spot for natural gas producers

InvestorRelations-NewsReleasesVeteran oilman Mike Rose says he doesn’t want to “jinx it,” but he admits it’s not so bad heading the company that last year became the biggest producer of natural gas in Canada.

While many oil companies have curtailed production and chopped capital budgets to deal with a massive drop in demand for crude this year, Tourmaline Oil Corp. has been buying assets, running a fleet of 10 drilling rigs and reporting production at the high end of guidance.

“On the oil side, that’s where the crisis was in March and April, and there was hue and cry from all governments and industry,” said Rose, who has been CEO of Tourmaline since its founding in 2008.

“But the reality is we’ve had horrible gas prices for five years and it didn’t seem to be as big a crisis. The gas producers that survived have figured out how to survive very low prices for extended periods of time. So that’s partly why we’re a little healthier.”

Natural gas has been considered by many as little more than an unprofitable byproduct for more than a decade, as the North American shale gas boom launched billions of cubic feet of the heating fuel on markets, driving down prices.

Gas economics got worse five years later when the technology was adapted to extract crude oil from tight underground shale formations in Canada and the United States, a technique that also freed more billions of cubic feet of associated natural gas.

When the twin crises of the Russia-Saudi price war and COVID-19 outbreak hit earlier this year, oil producers stopped drilling and shut down producing wells to avoid selling at a loss.

In turn, the sudden withdrawal of gas byproducts created a shortage, sending prices higher.

Futures contracts at the Alberta marketing hub for gas to be delivered next year have recently surged to a nearly four-year high of about $2.75 per thousand cubic feet -for comparison, Tourmaline’s break-even price is about $1.75.

“In many ways, for the gas producers, what’s bad for oil is good for gas,” said Jordan McNiven, an analyst for Tudor Pickering Holt & Co.

A seasonal increase in gas demand this winter, combined with an expected recovery in global liquefied natural gas demand as economies recover from the pandemic, is expected to spur North American gas prices even higher, analysts say.

“We’re constructive on the gas quote. We could see reasons why it could flex higher,” said Robert Fitzmartyn, head of energy institutional research at Stifel FirstEnergy.

The rise of natural gas has been noticed at Canadian Natural Resources Ltd., the Calgary-based oilsands giant that was Canada’s top gas producer before being dethroned last year.

In May, Canadian Natural announced it would reboot drilling on its long-ignored natural gas fields to add about 60 million cf/d to its long-standing output of around 1.4 billion cf/d.

Earlier this month, it doubled down on that interest by announcing a $461-million deal to buy Calgary rival Painted Pony Energy Ltd., which produces 270 million cf/d of natural gas in northeastern B.C.

“When we went into this year we thought prices would be a little more depressed,” said Canadian Natural president Tim McKay in an interview after its second-quarter results were released last week.

“They’ve been quite strong and that gives us the opportunity to ramp up some volumes.”

The oil price crash is reflected in share prices. As of Tuesday, the only positive stock year-to-date of the 16 oil and gas producers on the S&P/TSX Capped Energy Index is Tourmaline, up 6.77% since Jan. 1.

The remainder have dropped between 20 and 70%, with ARC Resources Ltd., primarily a natural gas producer, down by the least amount with a 19.3% loss.

Last week, Tourmaline reported second-quarter production of more than 299,000 barrels of oil equivalent per day, up seven% over the same period last year, composed of 61,800 bpd of oil and liquids and 1.425 billion cubic feet of natural gas.

It reported its average gas price was up 16% but its average oil and liquids price fell by 41%.

Second-quarter cash flow -arrived at by subtracting operating and maintenance costs from revenue -came to $225 million, in line with $226 million in the same quarter of 2019. It expects $1.05 billion in cash flow this year on an $800-million capital budget.

The company aims to reach more than 322,000 boe/d by year-end after drilling 42 new wells in the third quarter and bringing on 57 more in the fourth. It estimates its 2020 average gas production will be 1.5 billion cf/d.

In April, Tourmaline completed the acquisition of Chinook Energy Inc. for $24.5 million and it bought several assets in northwestern Alberta for a total of $38.3 million.

Asked if there are more acquisitions to come, CEO Rose said, “Oh yeah. Potentially.”

He said Tourmaline’s success hinges on strict control over costs, careful marketing to extract every possible penny from every cubic foot of gas and never getting too deep in debt.

On the latter front, he predicts the company will pay down enough debt to achieve an enviable debt-to-cash-flow ratio of 1:1 or lower sometime this year, if prices hold up.

“Fortunately, finally, we’re looking at a pretty strong gas price recovery for 2021 and hopefully that extends into 2022,” he said.

“It’s looking a lot more positive on the natural gas side than it has for a while. But I don’t want to jinx it.”


File photo: Jeff McIntosh Canadian Press

Suncor CEO signals caution about restarting oil output as economy recovers

The CEO of Suncor Energy Inc. says the company won’t quickly ramp up oil production despite recent higher crude prices as the North American economy begins to reopen following the easing of lockdowns from the COVID-19 pandemic.

Mark Little says he won’t “bet the financial health” of the company on the nascent recovery, listing a host of risks including the possibility of a second wave of virus outbreaks.

On a conference call to discuss second-quarter results, Little reiterated his contention that the energy sector recovery will be led by consumers of its refined products, with higher demand for fuel translating into more demand for oil.

Little says Suncor’s refinery utilization rate of 76% in the three months ended June 30 (allowing crude throughput of 350,400 barrels per day), was well ahead of industry averages, and credited that to its ability to assess customer needs through its wholesale and retail networks, including its Petro-Canada service stations.

Suncor’s total production was 655,500 barrels of oil equivalent per day during the second quarter, 18.5% less than the 803,900 boe/d in the prior year quarter, as it took measures including shutting down one of the two production trains at its 194,000-bpd Fort Hills oilsands mine in northern Alberta.

Little said putting the second train back in service depends on oil prices, the ongoing Alberta oil output curtailment program which has prevented full production at Fort Hills and Suncor’s ability to control costs.

“During the second half of 2020 we see continued strengthening of downstream (refining) demand in gasoline and diesel to more seasonal levels by the end of the year,” said Little.

“Given the high level of global crude inventories and the return of production which was shut in during the second quarter, we expect (oil) pricing and crude spread volatility to remain through 2020, although obviously not as extreme as we saw in the second quarter.”

It reported a second-quarter net loss of $614 million or 40 cents per share, down from net earnings of $2.73 billion or $1.74 per share in the same period of 2019, but ahead of analyst expectations of a net loss of $1.28 billion, according to Refinitiv.


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PrairieSky Royalty reports lower second quarter crude oil production

Oil production is beginning to recover after it was curtailed by an average of 30% in the second quarter due to low crude prices, PrairieSky Royalty Ltd. said Tuesday.

The Calgary-based company, which earns revenue by sharing in production from lands for which it holds the petroleum mineral rights, said it produced 18,670 barrels of oil equivalent per day in the three months ended June 30, down 16% from the first quarter.

No new wells were started on its properties in the three months ended June 30 but there are signs that activity will pick up later this year as oil pricesstrengthen, said CEO Andrew Phillips on a conference call.

“We do expect greater activity than we would have two months ago… I don’t know that will show an effect for us in the back half of this year, but it certainly will improve in 2021,” he said.

PrairieSky’s production shortfalls are expected to be a common theme as larger oilpatch players including Suncor Energy Inc. and Cenovus Energy Corp. roll out second quarter results later this week.

Producers in Western Canada are estimated to have shut down wells producing more than 800,000 barrels per day of oil at times in the second quarter due to plunging prices amid the economic downturn associated with the COVID-19 lockdowns.

Crude oil production at PrairieSky fell by 30% to 6,035 barrels per day over the quarter from 8,740 bpd in the year-earlier period as its average realized price fell to C$24.31 per barrel from C$65.48.

PrairieSky says as much as 40% of its oil output was curtailed in May.

Natural gas output was down 7.5% from the second quarter of 2019 despite the average price rising from 74 cents per thousand cubic feet to $1.39.

The company’s second quarter production revenue was $25.1 million, off by 39% compared with the first quarter of 2020 and 60% from the second quarter of 2019.

PrairieSky reported a net loss of $400,000 or zero cents per share in the quarter, compared with a net profit of $44 million or 19 cents in the year-earlier period, largely matching analyst expectations.

Its stock rose by as much as seven% to $8.90 on the Toronto Stock Exchange on Tuesday.

The company reported completing $6 million in royalty interest acquisitions in northeastern B.C. during the quarter and added it is continuing to look for expansion opportunities.


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Western oil heads east

UnknownThe first shipment of Alberta crude from British Columbia tidewater is on its way to the Irving Oil refining facility in Saint John. The route will take the Panama-flagged tanker, Cabo de Hornos, 11,900 kilometres from Burnaby, B.C. via the Panama Canal to New Brunswick.

The petroleum, sourced through Alberta energy company Cenovus, comes just two months after Irving announced it would seek greater Western Canadian resources for its East Coast facilities following the demise of the Energy East Pipeline project. The (CAN) $12 billion Energy East Pipeline was proposed by TransCanada (TC) Pipelines in 2013 and would have travelled 4,600 kilometres to points in Quebec and New Brunswick. If completed the line would have been among the world’s longest and would have carried 1 million barrels of Alberta and Saskatchewan crude per day. Following the election of the Trudeau government, the project was scrapped in 2017, leaving Eastern Canadian-based operators, such as Irving, to continue to source both refined and raw petroleum from the U.S. and other markets.

Now, using the Panama Canal route Irving will see the 229-metre Cabo de Hornos vessel arrive July 14 at refinery receiving docks in Saint John. After the Energy East Project was shelved, Irving approached the Canadian Transportation Agency (CTA) this spring (April) to ask for permission to use foreign tankers in an effort to increase the amount of domestic crude Irving gets from offshore Newfoundland and Western Canada. Approval was granted in May and Irving got busy making arrangements.

Irving has reported that it was importing the vast majority of its refinery inputs from sites in the U.S. and was using about 20% Canadian petroleum in its operations. In its application to the CTA Irving Oil stated that they sought to lessen their reliance on foreign petroleum at their Saint John facility, which is Canada’s largest refinery with a daily processing capacity of 320,000 barrels per day.

“It is critical to our customers, to our business, and to energy security throughout Atlantic Canada that we are able to use foreign crude oil tankers to access Western Canadian crude oil on an urgent basis and going forward for one year to allow for effective and flexible supply chain planning and to strengthen the link between Canadian oil producers and our refinery in this challenging and uncertain time,” said Irving Oil chief refining and supply officer Kevin Scott.

OCTANE editor Kelly Gray can be reached at Kgray@ensembleiq.com.


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Oil and gas spending estimates adjusted lower as uncertainties persist

New forecasts show dramatically lower expectations for 2020 capital spending in the oil and gas sector both nationally and in Alberta, the province that produces 65% of the country’s natural gas and 82% of its oil.

The Canadian Association of Petroleum Producers now estimates that $23.3 billion will be spent in the oil and gas production sector in Canada this year, down from about $37 billion in its January forecast.

Producers have announced billions of dollars in budget cuts since the start of the year to cope with lower oil prices as global energy demand plummets due to measures taken to control the COVID-19 pandemic.

Its January prediction represented about a 6% increase over 2019, credited to new industry friendly policies in Alberta and Saskatchewan and growing optimism that export pipeline capacity would be added.

The Alberta Energy Regulator, meanwhile, estimates that oil and gas capital spending in the province this year will fall to between $14.1 billion and $16.4 billion as price uncertainties continue to hurt producer confidence.

In its energy outlook posted Monday, the regulator says capital spending fell by 31% in 2019 to $18.9 billion. It attributed the 2019 drop to uncertainties around energy policy, low energy prices and market access constraints.


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Irving buys Come By Chance refinery

Move enhances company’s market edge

UnknownIrving Oil has announced the completion of its acquisition of North Atlantic Refining Corp. from U.S.-based investment firm Silverpeak. The deal, with undisclosed financial terms, includes a 135,000-barrels-per-day (bpd) refinery located at Come By Chance, NL, as well as a network of retail sites and other marketing assets.

Unknown-1The retail locations include nearly 100 company-owned and dealer sites and cardlocks, including the Orangestore chain of 24 convenience stores. North Atlantic Refining Corp has been a well-known major player in the province’s stove oil, gasoline, and propane trade since 1950.

The Newfoundland refinery is one that comes with a storied past of bankruptcies and business losses. Bought and sold a number of times since it went into service in the early 1970s, the facility was built to refine light crude and takes about 70% of its inputs from sources in the U.S. Silverpeak had recently invested $400 million to bring capacity up from about 100,000 bpd to 135,000bpd. Proposed is a further upgrade that would increase output to more than 165,000bbd and add a new coker that would allow a heavier grade of crude to be refined.

This initiative that is now in Irving’s court would bode well for the company given that they just arranged to ‘import’ Albertan heavy bitumen via tankers through the Panama Canal route. As well, Newfoundland and Labrador offshore wells also produce heavier crude and with an upgrade, the Come By Chance facility could finally refine the locally sourced heavy oil.

The Come By Chance refinery and the North Atlantic Refining Corp. convenience retail and fuel network in Newfoundland and Labrador is a strategic fit for Irving. With the closing of the Silverpoint deal, Irving will now operate the only two refineries in the Atlantic region. The other is Canada’s largest refinery at 320,000bbd and is located at St. John, NB. These facilities are married to another refinery in Cork, Ireland (71,000bbd). Together this recent agreement gives Irving a solid footing in fuel refining in the North Atlantic basin as well as an uptick in retail locations that create a greater market presence for this Halifax-based family business.

Kgray@ensembleiq.com


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Oil and gas drilling forecast revised to 49 year low as producers cut spending

Unknown-1The Petroleum Services Association of Canada has revised its 2020 Canadian drilling forecast to an almost 50-year record low of 3,100 oil and gas wells, a level not seen since 2,900 wells were drilled in 1972.

PSAC interim CEO Elizabeth Aquin says more than $7 billion of capital investment in the energy sector has been cancelled to date this year thanks to demand destruction from measures to deal with the COVID-19 pandemic and a supply surplus due to an oil price war between Russia and Saudi Arabia.

She said blockades of the Coastal GasLink Pipeline and cancellation of the Frontier oilsands project have also hurt investor confidence in the Canadian oil and gas industry.

PSAC chairman Mark O’Byrne says the industry appreciates government assistance such as $1.7 billion in federal funding to clean up orphan and inactive wells in Alberta, Saskatchewan and British Columbia, but will need more help to ensure survival.

The new forecast represents a decrease of 1,400 wells, or 31%, from PSAC’s original forecast of 4,500 wells announced in October.

About 4,900 wells were drilled in 2019.

“The majority of the impact will be felt on the oil side as supply overwhelms demand and storage levels surge to capacity,” said Aquin.

“This has left producers little incentive to drill for more with the price of a barrel of oil now fetching less than a cup of coffee. We expect to see a 38% drop in activity for oil wells versus 2019.”


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Project deferral, oil prices troubling for N.L. economy during pandemic

Unknown-2The global COVID-19 pandemic is spelling trouble for Newfoundland and Labrador’s oil and gas industry, adding to existing economic challenges in the cash-strapped province.

Premier Dwight Ball acknowledged last week the province is experiencing “tough times,” referencing deferred investment on projects and historic lows in oil prices.

Equinor and Husky Energy announced the decision to defer the Bay du Nord offshore development project due to falling oil prices and economic downturn as countries respond to the novel coronavirus.

A statement from Equinor Canada says planning on the project will continue with adjusted timelines.

The project in the Flemish Pass Basin, about 500 kilometres east of St. John’s, was announced in 2018 but not yet officially sanctioned. Equinor had set a target of 2020 to decide.

The Bay du Nord project was expected to deliver first oil by 2025. It was a key part of the province’s plan to rapidly increase offshore oil and gasdevelopment, including a goal to double production to more than 650,000 barrels a day by 2030.

Natural Resources Minister Siobhan Coady said the news is disappointing, but she said it’s a positive sign that the project is deferred rather than cancelled during such a tumultuous time.

“These are difficult times, there’s no doubt, and it was difficult to hear that they’re deferring their decision,” Coady said by phone. “I remain kind of optimistic that things will move into a better place as we move forward.”

She said she remains encouraged by exploration ongoing in the province’s offshore.

Ball urged the federal government to take quick action on financial support for provinces on Wednesday but said Ottawa should not respond with a one-size-fits-all approach.

“My message to the federal government is, it’s urgent to get this money moving,” Ball said on Wednesday.

Larry Short, a chartered professional accountant who owns an investment firm in St. John’s, said the situation adds up to a “body blow” for the province’s finances.

“All the bad parts of the Bible have been delivered upon the province, and all the same time,” Short said by phone Thursday.

Short pointed to the immediacy of the COVID-19 crisis, the billions over-budget Muskrat Falls hydro project that accounts for a third of the province’s debt and the oil price collapse as serious challenges to the province’s budget that can’t be ignored much longer.

“We’ve got three major problems here that have suddenly come home to roost, and the province is going to have to really struggle to get through them over the next period of time,” he said.

He said the effects may not be seen until the government tables its budget, likely in the summer after a Liberal Party election set for May that will determine the new party leader and premier.

But with the federal government experiencing financial difficulties of its own, including major blows to Alberta’s oil-reliant economy, Short said Ottawa won’t be in a position to assist Newfoundland and Labrador financially as it normally would.

While prices are being hit hard right now by barrels of cheap oil from Russia and Saudi Arabia, he said Newfoundland and Labrador’s offshore might be left standing as a profitable and desirable drilling site once prices rise again, as the industry is less susceptible to disruptions like pipeline project delays.


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Suncor defers Montreal refinery project to focus on low cost oilsands expansions

Suncor Energy Inc.’s on-again, off-again plan to add a coker unit to its Montreal refinery to allow it to process heavier barrels of oil, including oilsands bitumen, is off the table as it shuffles its spending priorities.

The $2-billion project has been shelved as the company focuses on low-cost oilsands expansions, projects that will help reduce emissions and cost-cutting digital technologies, CEO Mark Little said on a conference call to discuss fourth-quarter results.

Little said the company is listening to investors as it aims to generate more free cash flow while keeping spending in check.

“Some of the concern we see from the investors is, ‘Wow, you’re going to plow $2 billion into Montreal, are you sure?’,” he said.

“We spent a lot of time thinking about that and running all the analysis and concluded that actually wasn’t the prudent investment for the shareholder.”

Suncor also elected to defer sanctioning of its proposed 40,000-barrel-per-day Meadow Creek oilsands project, which would produce bitumen from wells, until 2023 at the earliest, Little said.

Instead, it will invest in boosting production from its existing similar Firebag facility to nameplate capacity of 203,000 bpd by 2021 and then potentially add 20,000-30,000 bpd by 2024-25.

It also plans to build lower-emission co-generation units at its Base Plant this year and begin construction of a $300-million wind power project in southern Alberta.

The Calgary-based energy giant reported a net loss of $2.3 billion for quarter ended Dec. 31 due mainly to asset impairment charges of $3.3 billion.

That includes $2.8 billion due to lower forecast prices for heavy oil from its Fort Hills oilsands mine in northern Alberta and $393 million linked to higher capital cost estimates for the West White Rose expansion project off the coast of Newfoundland and Labrador, which is expected to begin producing oil in 2022.

Husky Energy Inc., which is the major owner and operator of the White Rose field, said its numbers align with those of Suncor.

“As indicated last year, we had some initial challenges with productivity at West White Rose, and we are now seeing good execution and are on track,” said Husky spokeswoman Kim Guttormson, who declined to give a detailed cost estimate for the expansion.

Suncor said it expects its share of production from the White Rose field will average about 8,700 bpd over its life and its share of future capital expenditures is about $1.4 billion.

Suncor shares fell by as much as 4.6% in early trading on the Toronto Stock Exchange, although it announced an 11% increase in its quarterly dividend and a $2-billion extension of its program to buy back shares.

Analysts said its production results were generally in line, but misses on its operating and capital costs in the quarter were slightly negative.

Little also announced Suncor will file an application in the current quarter for a project to extend its base oilsands mine to a new area when its current resource is depleted in about 2035.

The project represents one of many options and wouldn’t be officially approved for at least a decade, he stressed.

“We feel that filing in 2020 is prudent under the current regulatory process, including the effects of the new (federal) assessment act, to ensure adequate time is provided for the regulatory process,” he said.

“Should we choose to extend the mine, the plan is to incorporate non-aqueous extraction technology which significantly reduces the costs and environmental impacts of mining oilsands versus our current operations.”

Suncor reported its MacKay River oilsands project, which produces about 30,000 bpd from wells, was shut down following an operational problem in December and is not expected back to be back on line until after March.

The outage won’t affect 2020 guidance for the company, Little said, because the loss of barrels can be counted under Alberta’s ongoing oil production curtailment program.