Alberta energy regulator releases rules on heavy oil odours after long-standing complaints

CALGARY — Alberta’s energy regulator is setting new rules to deal with long-standing complaints about powerful, gassy smells from heavy oil operations in the Peace River region.

The rules grew out of a 2014 inquiry after years of complaints from people in tiny communities neighbouring the operations.

They set limits on how much gas operators are allowed to flare off and requires them to control odours coming from trucks or tanks being cleaned.

They also include extensive reporting requirements and say operators must join local air quality management programs.

The inquiry also made recommendations to the provincial government, none of which is yet in place.

Area residents were still complaining about odours from the oilpatch as recently as last fall.

The 2014 inquiry concluded the smells were damaging people’s health.

The Canadian Press

‘Unloved’ Crescent Point denies activist investor rumours, defends recent management decisions

CALGARY — The CEO of Crescent Point Energy Corp. shot down rumours Thursday that the company has been approached by an unknown activist investor, as the company continues to face a recent fall from favour in the oilpatch investor community.

“In our entire history we have never had or been approached by an activist [investor],” Crescent Point CEO Scott Saxberg said in a conference call with analysts. “So that’s all I really can say to that.”

The company’s stellar reputation suffered following a series of mis-communicated management decisions, which has led to uncertainty over what steps the company should take to improve its corporate standing.

That uncertainty fed rumours late last week that an unnamed activist investor could be preparing to buy a position in the company. The speculation arose after a newsletter based out of the U.S. mentioned the rumour, citing anonymous sources.

AltaCorp Capital Inc. analyst Thomas Matthews said speculation tends to intensify around corporations that are struggling, which in turn feeds widespread theories over what could be in the works.

“When investor sentiment completely abandons a company, which it did after the last Crescent Point equity financing, and it’s so unloved, you start to hear rumours—and most of them are unfounded,” he said.

“There’s been no shortage of rumours surrounding Crescent Point over the last three to six months.”

The company’s struggles intensified in September 2016 following a $660-million equity issuance that diluted the company’s shares while showing little sign of recovering its total initial value.

Management said the proceeds from the issuance would be used to shore up Crescent Point’s balance sheet, but was instead largely used in the company’s operations, which further vexed shareholders, Matthews said.

“We realize that communication around our recent financing could have been better,” Saxberg said Thursday in a discussion about the company’s 2016 financial and operating results.

He said the company was working to correct some of its recent missteps through discussions with investors.

“We’ve had a lot of conversations over this last year with our shareholders, taken a lot of their feedback, and responded and tried to be proactive.”

Crescent Point went public in 2001 as a junior exploration company and grew to become among Canada’s largest producers, with operations in Saskatchewan, the Williston Basin and the Uinta Basin in the U.S. Over time the company earned a reputation as a stable, dividend-paying corporation, becoming a favoured stock pick among investors.

But confidence began to fade when the Crescent Point management assumed a bullish stance on its dividend levels, indicating that it planned to maintain rates despite falling oil prices.

“Back at the start of 2016 and even into late 2015, Crescent Point was taking these very hard lines in the sand,” Matthews said.

That position came just after the company had cut its dividend in August 2015 for the first time in its 14-year history, from 23 cents per share to ten cents. But in March 2016, as the oil rout deepened, the company was forced to slash its dividend again, down to three cents per share.

“I don’t think they anticipated just how low oil prices were going to go,” Matthews said. “So that was the first sour taste in investors’ mouths.”

Despite its struggles, Matthews said the company’s year-end results showed some encouraging results.

Crescent Point beat its production estimates for the year, surpassing an average 167,000 barrels of oil equivalent per day, up from over 163,000 boed in 2015.

The company ramped up production through successive improvements in its operations, particularly using a process known as “waterflooding,” where water is injected down an aging well to push higher volumes of oil to surface.

The technique led to a boosting of the company’s reserve base. In 2016 it booked a total of 10.5 million barrels of new reserves through the process, following a 4.5 million barrel increase in 2015. Management said the method could potentially unlock much larger volumes of oil as the process continues.

The company reported an annual loss of $932 million, or $1.81 per share, largely due to a $457 million impairment charge in the fourth quarter. In 2015 the company recorded a $870-million loss, or $1.82 per share.

Alberta out of recession, but government keeps deficit forecast steady

CALGARY – Alberta’s long recession appears to have ended but the provincial government will continue to borrow billions of dollars to cover expenses for the next year, contravened one of its own financial laws.

The province released its third quarter fiscal update Thursday, which showed 18,000 jobs had been added in the province since employment troughed in July 2016. The majority of those jobs, 12,000 positions, were in the oilfield, where the government expects drilling activity to continue to recover.

The budget shortfall is expected to be $10.8 billion, unchanged from the government’s last forecast in November, but higher than the $10.4 billion gap originally forecast in the 2016-17 budget released in April.

At the same time, however, the budget update showed the government was no longer in compliance with its own Fiscal Planning and Transparency Act, which the NDP made law in 2015, thanks to increased expenses and a $1 billion planned payout to coal-fired power producers.

The act was meant to limit unplanned hikes in operating expenses to 1 per cent of the budget, but the government now projects operating expenses will be roughly 5 per cent higher than planned. In total, the province now expects to spend $53.7 billion this fiscal year, which is up $2.6 billion from budget.

In the past, multiple ratings agencies cut Alberta’s credit rating as a result of what Moody’s Investors Services called an “unconstrained debt burden.”

“A full economic recovery will take time after such a long downturn but we are starting to see encouraging signs for Alberta in the year ahead,” Alberta’s Finance Minister Joe Ceci said in a release, adding that “some challenges still remain” and “we will continue to protect the services that Albertans depend on.”

To fund those services next year, the budget update showed the government is increasing the province’s borrowing base this year by $14.5 billion and had begun selling bonds, including a deal in the British pound struck with U.K. lenders on Wednesday, to take advantage of currently low interest rates.

The province’s increased spending this year will be partly offset by better-than-expected revenues of $42.9 billion, $1.5 billion more than forecast, thanks in large part to higher oil and gas prices and royalties.

However, corporate income tax revenues are now expected to be $981 million lower than originally forecast. The province attributed a third of that decline to losses incurred during the wildfire that devastated Fort McMurray and area during the summer of 2016 but also to a weaker than expected economy.

The government now expects Alberta’s real gross domestic product to rise 2.4 per cent in 2017 following a 2.8 per cent contraction in the economy in 2016 and a 3.6 per cent contraction in 2015.

The estimate might be conservative given the Conference Board of Canada predicted Alberta’s economy would outpace that of every other province when releasing its own forecast Thursday, which predicted Alberta’s real GDP would grow 2.8 per cent in 2017 as a result of rising oil production.

Financial Post with file from Reuters

Oil demand uncertainty at peak as pundits caught between denial and exuberance

Get yourself a ruler, a pencil and a piece of paper. Place the ruler at about 45 degrees and draw a line upward across the page.

That’s what a chart of world oil consumption looks like over the past 30 years, give or take a few shakes off the line.

That was easy. Now think about how to draw oil consumption over the next three decades.

Plenty of pundits are scrubbing their spreadsheets and fidgeting with their rulers to show us the answer.

Some forecasters are economists who work for multinational oil and gas companies and government agencies. Most of their oil outlooks extend upward. The biggest uncertainty is the angle of their rulers.

The steepest slope assumes that our prevailing consumption habits and government policies are extended out a few more decades. Oil demand reaches nearly 120 million barrels per day at the top of this cluster, up almost 25 per cent from today.

More moderate trajectories in the group are based on pledges made pursuant to the November 2015 Paris Climate Change Conference; but tallying up country commitments still suggests modest growth to between 100 and 105 million bpd by 2040.

A group of weaker outlooks tilt downward like a loosely held hockey stick. Clustering between 73 and 80 million bpd by 2040, this collection of prognostications assumes more aggressive global efforts to limit carbon loading in the atmosphere and the faster adoption of innovations like electric vehicles. The International Energy Agency’s 450 Scenario is the most bearish demand outlook among these peers.

20170222-figure-1Environmental groups don’t equate fossil energy usage to classroom instruments or clichéd sports equipment. Slick oil charts from naysayers with green-coloured glasses look more like a BASE jump gone badly. The most catastrophic scenario appears to come from Greenpeace, which proposes that pipelines will trickle in the range of 35 million bpd by 2040.

What and whom to believe? The range of consumption estimates 25-years out is wider than the tailgate of a Ford F350; on one end is 35 million bpd, on the other 120 million bpd. Even the top cluster varies by 20 per cent.

Given the 80 million bpd range in opinions and analyses (each convincing on their own), stakeholders in the oil business may feel a tendency to adopt a, “the truth lies in the middle,” forecast. This method instructs us to believe a midpoint somewhere between denial and exuberance.

Taking the median of all expert opinions and calling it the “consensus” of wisdom suggests oil demand will drop by 20 per cent over the next quarter century. I don’t find this approach satisfying. Looking through a row of ten cloudy crystal balls doesn’t yield a new one of greater clarity.

20170222-figure-2For over 100 years, the oil industry and its stakeholders have believed that the market for their products will continue to grow ad infinitum without competitive challenges. Today, that thesis is about as useful as a bent ruler and a broken pencil.

Never in my 35-year career following energy markets has there been so much widespread disagreement about future demand for oil. And it’s a relatively recent confusion, one that’s been emerging over the past decade, but heightened in the past couple of years due to the potential forces of technological change and carbon regulation.

An 80 million bpd disagreement in various outlooks says to me that there is little value to add by uploading yet another spreadsheet into an already foggy cloud of forecast charts.

I’m only confident in one fact and one forecast.

Fact: There is widespread ambiguity in expert outlooks for oil consumption, one of the world’s most vital commodities.

Forecast: The uncertainty is not going to diminish over the next five years at least. In other words, trends in technology, policy, economy and social factors are going to put wider and wider error bars on every pundit’s numbers.

In my mind, the fuzzy question of, “How much oil is the world going to consume by 2030 and beyond?” must now yield to sharper, qualitative thinking.

Pencils and rulers down, the questions going forward are, “What type of decisions will be made—relating to investment, corporate strategy, government policy and so on—under unprecedented uncertainty, and how will these near-term decisions affect the world’s long-term energy future?”

I’ll be pondering answers to these questions during my commute to work and back in my new electric vehicle.

Peter Tertzakian is Executive Director of the ARC Energy Research Institute in Calgary, Alberta.

Vancouver seeking judicial review of Trans Mountain pipeline expansion

VANCOUVER — The City of Vancouver is launching another court case in a bid to derail Kinder Morgan’s proposed pipeline expansion.

Council members have voted to go ahead with a judicial review of the provincial government’s environmental assessment of the Trans Mountain project.

In June, the city filed another court challenge aimed at quashing the National Energy Board’s recommended approval of the $6.8-billion project.

The federal government has already approved the expansion, which would triple the capacity of a pipeline that runs from near Edmonton to Metro Vancouver, and increase tanker traffic in the Burrard Inlet seven-fold.

B.C. Premier Christy Clark said last month that all five of the province’s conditions for approving the project had been met, including First Nations participation and the creation of world-leading oil spill response and prevention plans.

Several other groups, including the Squamish Nation, the Living Oceans Society and the Raincoast Conservation Foundation, have filed their own applications for judicial review of the project.

Why the Canadian oil sands caused a bigger hit to exporters than other petroleum projects

Oil-sands investments in Western Canada that gobbled tens of billions of dollars over the past decade are proving an Achilles heel for some of the world’s biggest energy producers.

Exxon Mobil Corp. slashed proved reserves the most in its modern history after removing the entire $16 billion, 3.5-billion-barrel Kearl oil-sands project from its books on Wednesday. That followed ConocoPhillips’ announcement a day earlier that erasing 1.15 billion oil-sands barrels plunged its reserves to a 15-year low.

While prolific shale plays in Texas and Oklahoma are going through an investment boom with oil above $50 a barrel, the oil sands have fallen out of favour. Current investments in the region amount mostly to long-planned expansions by large Canadian producers like Suncor Energy Inc., while majors like Statoil ASA have sold assets.

The oil-sands mines in northern Alberta are among the costliest types of petroleum projects to develop because the raw bitumen extracted from the region must be processed and converted to a thick, synthetic crude oil. In addition, Canadian crude sells for less than benchmark U.S. crude because of the added cost to ship it to American refineries and an abundance of competing supplies from shale fields. That’s why the oil sands have been particularly hard hit by the worst oil slump in a generation.

The combined 4.65 billion barrels of oil-sands crude removed from Exxon’s and Conoco’s books are worth US$183 billion, based on current prices for the Western Canada Select benchmark. The revisions hit as both U.S. companies, along with the rest of the oil industry, strove to recover from a 2 1/2-year market slump that collapsed cash flows, wiped out hundreds of thousands of jobs and prompted many explorers to cancel their most ambitious drilling programs.

Mark Ralston/AFP/Getty Images

Mark Ralston/AFP/Getty Images

Under U.S. Securities and Exchange Commission rules, proved reserves can only include oil and gas fields that can be produced economically within the next half decade. Price trends from the previous 12 months are compared against the estimated cost to harvest crude and gas in determining which reserves are counted.

The revisions of what qualifies as proved reserves are not expected to affect the operation of the underlying projects or to alter the company’s outlook for future production volumes, Exxon said.

Exxon’s 19 percent cut to global proved reserves amounted to the largest annual revision since at least the 1999 merger that created the company in its modern form, according to data compiled by Bloomberg. That included 1.5 billion barrels of reserves that were pumped from wells across the globe. The previous record cut was a 3 percent reduction taken during the height of the global financial crisis in 2008.

ConocoPhillips on Tuesday shrank proved reserves by more than one-fifth, the majority of it stemming from its de-booking of oil-sands crude.



Reserves are a key metric watched by investors because they are an indicator, along with commodity prices, of future cash flow. When the 2008 reserves cut was announced in February 2009, Exxon shares lost more than 4 percent in a single day, wiping out almost $17 billion in market value.

Exxon, facing a SEC probe into how it valued its portfolio amid the worst oil market collapse in a generation, signalled in October and again last month that the revision was probably coming.

The world’s largest oil explorer by market value held out hope that the de-booked barrels will one day be restored to the proved reserves category. Higher energy prices or lower expenses to produce oil could improve the outlook for developing those fields, the company said.

“Prices to date in 2017 have been higher than the average first-of-month prices in 2016,” the Irving, Texas-based company said in a statement on Wednesday. “These revisions are not expected to affect the operation of the underlying projects or to alter the company’s outlook for future production volumes.”

Canada’s Crescent Point Energy posts bigger quarterly loss

Canada’s Crescent Point Energy Corp reported a bigger quarterly loss from a year earlier, mainly hurt by one-time charges of about $457 million.

The oil and gas producer’s net loss widened to $510.6 million (US$388.23 million), or 94 cents per share, in the fourth quarter ended Dec. 31, from $382.4 million, or 76 cents per share, a year earlier.

The quarter also included an unrealized loss on derivatives of $138.7 million. Crescent recorded one-time charges of about $589.4 million in the year ago quarter.

Total average production fell 6.3 percent to 165,097 barrels of oil equivalent per day in the quarter.

A jobless recovery: Why the layoffs are not over in the oilpatch — despite US$50 oil

CALGARY – Oil and gas companies laid off tens of thousands of people during the two-year-long collapse in crude prices and, a new study shows, some companies plan further reductions.

Ernst and Young and the University of Calgary’s Haskayne School of Business conducted a survey of 72 Canadian oil and gas companies and asked, given all the staff cuts that have been made over the past couple of years, whether executives are considering further changes to their organizations.

“Most are considering further changes in the future,” EY’s Canadian strategy services leader, oil and gas Lance Mortlock said in an interview. “Now, we’re seeing changes around, is there a better way of doing this? Is there a better way of organizing how we get work done?”

Mortlock said that companies reacted with layoffs to survive when crude oil prices began to fall in the second half of 2014 but are now considering “different ways that you can do work – better, faster, cheaper – with less people involved.”

“I think executive teams are challenging themselves to find new ways of getting work done,” Mortlock said and cited robotics and process automation as options energy companies are considering to further drive down costs.

The study released Thursday reflects a widespread expectation in the oilpatch that the oil price recovery is likely to be a jobless one, where companies – spooked by continued commodity price volatility – continue to focus on cutting costs.

The U.S. West Texas Intermediate crude April contract, the new front-month future, settled 1.4 per cent lower at US$53.59 per barrel Wednesday. The price has nearly doubled after hitting a bottom of US$26 in February 2016, but remains below the comfort level of most producers.

The survey showed that 80 per cent of Canadian oil and gas companies had reduced their headcount over the last two years – and 9 per cent of the respondent companies, particularly in oilfield services and upstream exploration, cut more than 50 per cent of their staff.

The result was 30,000 direct job losses in Alberta alone, according to Canadian government data.

“While the majority of our market study respondents reported high levels of success with their reorganizations, many indicated that there are further changes to come,” Haskayne School of Business associate professor Peter Sherer said in a release.

The study showed companies that took a longer-term approach to the oil price collapse – by reducing salaries and re-assigning employees rather than just staff cuts – tended to be most satisfied with their reorganizations.

Roughly half, 49 per cent, of the respondent companies cut their headcount between 10 per cent and 35 per cent during the downturn and 81 per cent of those companies said their cost cutting efforts had above-average success rates.

Asked whether there were segments within the oil and gas industry that could see job growth if oil prices trended upward, Mortlock said, “If there’s one industry that concerns me the most, it’s oilfield services.”

Oilfield services companies were the most likely to reduce their headcount by more than 50 per cent during the downturn, he said, and might also be most likely to be under pressure to hire again quickly if oilfield activity rebounds.

Drilling activity has rebounded from record lows set last year, but has yet to reach pre-downturn levels. In the last quarter of 2016, there were 172 drilling rigs working in Canada, up slightly from 168 during the same period in 2015, but a long way from the 384 rigs working at the end of 2014, according to the Canadian Association of Oilwell Drilling Contractors. The number of rigs working in Canada increased sharply to 279 in January.

Financial Post