Category Archives: economic impact
Sask. economic ‘bright spot’ hit with new tariff
April 25, 2017 – 4:51pmUpdated: April 26, 2017 – 6:45am
Forestry remains a key industry in northern Saskatchewan, where it is the second most important economic driver.
Quebec and B.C. will be hit the hardest by new duties imposed on the Canadian softwood lumber bound for the U.S. – but they won’t be the only ones.
On Tuesday, the Trump administration announced its first batch of duties on imported wood in the neighbourhood of 20 per cent.
Forestry remains an important industry in northern Saskatchewan, where it is a key economic driver.
“We export about $550-million worth of forest products, largely into the United States,” said Chris Dekker, president and CEO of Saskatchewan Trade Export Partnership.
“Any trade barrier to what we produce and export abroad is going to be concerning, not only to the economy, but to the industry itself.”
The new tariffs come during a positive period for the Saskatchewan forestry industry. Dekker called it a “bright spot,” noting an “upsurge of late” at a time when other parts of the provincial economy have faltered.
“There’s about 13,000 direct and indirect jobs across the industry and our sales, exports in that industry have been climbing, counter to other exports where commodity prices have been decreasing,” he said.
But Dekker also pointed out only a minority portion of Saskatchewan’s annual forest product exports to the U.S. are in softwood lumber.
“There’s a lot of pulp and a lot of oriented strand board. Only about $84 million of exports is in the softwood lumber area,” he said.
Over the short term, Dekker doesn’t expect these new tariffs to have a serious impact in this province. As for the long term, he’s waiting to see.
“They have announced that this new duty is as a result of an investigation that has been ongoing. Now, there is a second and parallel anti-dumping investigation that is also going on,” he said.
“That could come out this summer and the duty rate that could apply as a result of that investigation could be established in the fall.”
The Canadian government condemned Tuesday’s announcement. In a statement, the federal government called the move unfair, baseless, unfounded and it promised help for its industry.
Natural Resources Minister Jim Carr said the action hurts people in both countries — not only Canada’s lumber sector that employs hundreds of thousands, but also American home-buyers, who must now pay more for wood.
The buildup to this new lumber war began with the 2015 expiry of a decade-old agreement. It stems from a fundamental, long-standing dispute over whether Canadian companies’ access to public land constitutes a subsidy.
Duties will be collected retroactively, too — the U.S. says it will gather them for the previous 90 days. Industry analysts have been expecting the combined duties — Monday’s and the upcoming ones — to range between 30 and 40 per cent.
Carrier Forest Products, a medium-sized company operating in Saskatchewan, will be among those forced to pay retroactive duties.
According to the company, it will cost Carrier millions of dollars and could mean job losses.
Whitecap, Raging River added the most employees of TSX-listed producers in 2016
By Mark Young
April 25, 2017, 12:42 p.m.
Whitecap Resources and Raging River Exploration saw full-time and part-time employee numbers increase by 62 and 54 percent, respectively, between 2015 and 2016, according to annual data available on CanOils.
The two companies top the list of TSX producers to increase employee numbers in the last year, despite the continued challenging environment for oil and gas producers worldwide.
At the other end of the spectrum, the TSX companies to let the highest portion of employees go this year were TransAtlantic Petroleum and Perpetual Energy. These companies cut their workforces by 59 and 57 percent, respectively, between 2015 and 2016.
Serial lumber litigation is a game of ‘heads I win, tails you lose’ for the U.S.
OTTAWA — The Globe and Mail
Published Tuesday, Apr. 25, 2017 5:03PM EDT
Last updated Tuesday, Apr. 25, 2017 5:06PM EDT
It is easy to figure out how U.S. tariffs on Canadian lumber will affect Americans.
It’s going to make U.S. homes, renovations and furniture more expensive. Even before Monday’s move by the Trump administration to hit Canada with a preliminary 20-per-cent duty, the price of lumber was rising in anticipation of the looming dispute. Lumber is up 22 per cent since January, adding roughly $3,600 (U.S.) to the price of a typical new home, according to the U.S. National Association of Home Builders.
A sustained price hike of this magnitude will put the dream of home ownership out of reach for nearly half a million Americans.
The United States can’t just produce more lumber. The country has traditionally relied on imports for roughly a third of its lumber needs – and virtually all of it comes from Canada. The math is pretty simple: Tax Canadian lumber, or restrict imports though a quota, and the price of lumber goes up.
Unfortunately, none of this matters. If this dispute was about the cost of a home, Canada would not be facing its fifth lumber trade war since the 1980s.
Canadian officials love to trot out U.S. home builder statistics to demonstrate how Americans are actually hurting themselves when they put a tariff on Canadian lumber.
“This decision will negatively affect workers on both sides of the border and will ultimately increase costs for American families who want to build or renovate homes,” Natural Resources Minister Jim Carr and Foreign Affairs Minister Chrystia Freeland said in a statement Monday.
These arguments did not win the day in the early 2000s or in any of the earlier showdowns. And they are unlikely to work this time.
Here’s why: The average price of a newly built U.S. home was $388,000 in March. Lumber adds less than $10,000 to the final price. That pales compared to the contribution of land, labour and interest rates to the final price. Lumber is little more than a rounding error in this calculation.
Nor is this a dispute fundamentally about saving U.S. logging and sawmilling jobs – although U.S. President Donald Trump will insist it is. Mr. Trump can “Buy American, Hire American” all he wants, but it won’t create more jobs in the highly automated logging and sawmilling business, and it could costs tens of thousands of U.S. home-building jobs.
The essence of this fight is about the market value of trees. Nearly three-quarters of U.S. forest land is in private hands in the United States. In Canada, just 10 per cent is, with the rest owned by governments.
There are more than 10 million small woodlot owners in the United States. A much smaller clutch of a few thousand very large forest owners are the driving force behind the U.S. Lumber Coalition, which launched this and earlier trade cases.
They have one motivation: increase the value of timber, which has become a phenomenal store of value in a world of slim investment yields.
Taxing Canadian lumber is an easy way to make that happen. Win or lose a trade case and it still pushes up the price of lumber, and more importantly, stumpage rates.
The economics made another trade case against Canada inevitable, in spite of previous lost rounds of litigation. The final duties applied on Canadian lumber are likely to be in the ballpark of the combined 27-per-cent anti-dumping and countervailing duty applied in the early 2000s.
Nothing has really changed in the intervening years. Canadian provinces still set the price of most harvestable trees. If anything, Canadian stumpage rates are more reflective of market prices than before and that should reduce the level of alleged subsidies.
What hasn’t changed is that litigation is a relatively cheap way to push up the value of U.S. lumber, trees and land.
For the U.S. industry, a loss hardly matters because lumber prices stay artificially high while the case plods along.
And if the U.S. Lumber Coalition is really lucky, Canada will eventually cave and agree to cap its exports. That also does the trick because squeezing supply inflates the value of U.S. trees, transferring wealth from U.S. consumers and Canadians to U.S. woodlot owners.
Tails I win. Heads you lose.
Waterflood technology is advancing Saskatchewan’s tight oil plays
By Elsie Ross
April 21, 2017, 2:31 p.m.
The horizontal drilling and multistage fracture stimulation revolution has opened up billions of barrels of resources in Saskatchewan to development. But the technology comes with one big downside—decline rates.
Decline rates on individual wells in the Bakken and Shaunavon plays can reach as high as 85 per cent in the first year, according to the Saskatchewan Research Council (SRC).
Viking declines are in the 60–70 per cent range during the same time period. This means operators ran a treadmill drilling new wells to manage corporate declines and add production.
Efforts are underway in all these plays to stem decline rates, allowing for more stable growth and reserve recovery through improved waterflood technologies.
A new technology that Crescent Point Energy is developing in Saskatchewan could potentially enable the company to maintain a steady annual decline rate even as it continues to grow, says a company official.
“If this technology works the way we think it is going to work, it’s not out of reach to have a 26–28 per cent decline rate that is holding in relatively steady even as we are growing at five to 10 per cent production, even with higher activity levels,” Trent Stangl, former senior vice-president of investor relations and communications, told a recent CIBC investment conference. The company “is not going back up to those 31 per cent to 32 per cent declines.”
Crescent Point has calculated that a reduction in the decline rate to 28 per cent from 35 per cent saved the company about $250 million, all other things being equal. “So it’s pretty significant.”
Three or four years ago, the decline rate would have been 35 per cent and this year with the incremental capital, it will be 28 per cent, he said.
The drop, though, isn’t due entirely to the waterflood. There also has been reduced activity, Stangl said, noting that at its peak, Crescent Point was running 29 rigs compared to 20–22 rigs for much of last year.
“But it’s not like there is a massive drop in activity levels,” said Stangl. “There certainly is a good component of that reduction in the waterflood.”
With the new technology, the company is able to put tools downhole to control the amount of water that is going into each of the ports. “It’s almost like a soaker hose for your lawn where you have the even distribution across the laterals.”
In the first couple of wells that it has done, Crescent Point has been able to get three times as much water into the wells, which is improving the reservoir pressure more quickly and is accelerating the response with production from the offset producer well actually going up after six months, he said.
“If we can prove this up with incremental wells, those same kind of results, that will have a dramatic effect on our waterflood,” said Stangl. “It will increase the response time, which will improve the economics.”
The company, he said, has about 300 wells currently injecting water into the Bakken and Shaunavon plays. By the end of the first quarter of 2017, it expected to put the new system in 45 of those wells so that by the second and third quarters of this year, Crescent Point will have a good idea of the response. “If that all works the way we think it is, we are going to have another 250 existing injection wells that we can convert.”
Stangl noted that in addition to the cost of the injection for the waterflood, there also is the cost of shutting in a producer well producing 10 bbls/d or 20 bbls/d in order to convert it to an injection well. “In the past, we have shut in 2,000–3,000 bbls/d every year to accelerate the waterflood.”
In the future, Crescent Point has another 250 wells it could do before it needs to shut in any more producers. “By that time, you’ll have that much more decline suppression, improving the economics.”
With the existing waterfloods, the decline rate on primary production has declined to 20 per cent from 30 per cent and in the Shaunavon Play, the decline rate is 14 per cent from 28 per cent. In the Bakken, the recovery factor is expected to improve to more than 30 per cent from 17–19 per cent.
New Viking waterflood shows promise
Although it’s early days, water injection into the Viking Formation in Saskatchewan seems to be working well for Raging River Exploration, which expects better recovery factors than achieved by earlier waterfloods in the same formation.
That was the message Jesse Barlow, Raging River’s vice-president of engineering, delivered recently at a joint Petroleum Technology Alliance of Canada (PTAC)-SRC workshop on light tight oil innovation.
To get better results than the old Viking waterfloods, Raging River uses saline-source water, better injector/producer ratios, tighter injector/producer spacing and higher-productivity multi-frac horizontal wells.
First waterflood reserves
Raging River is focused entirely on the Dodsland Viking light tight oil play in west-central Saskatchewan. According to the January 2017 presentation on its website, the company is spending $35 million in waterflood capital this year.
The Saskatchewan-focused producer hopes to gradually reduce its production decline rate to 17 per cent in 2026 from a projected 38 per cent this year.
In its reserves and operations update, Raging River said waterflood execution continues to be a priority in the first quarter with an estimated $20 million being spent on facilities.
The company’s first waterflood reserves were recorded in 2016 by its independent reserves evaluator, Sproule Associates, with about 700,000 barrels of oil being booked attributable to the ongoing waterfloods.
During the question period after his presentation at the PTAC-SRC workshop, Barlow said jokingly, “We want everyone in this room to implement as many waterfloods as possible so there’s lots of examples of successful waterfloods for the evaluators.”
He said evaluators like to see a bit more production history than Raging River currently has before booking a lot of reserves attributable to waterflooding.
Barlow discussed the primary causes of old waterflood failures in the Viking and what Raging River is doing to avoid those pitfalls.
One cause of past failure was the use of fresh-source water. He said the Viking has swelling clays, which makes fresh water extremely damaging to the formation.
Another cause of past failures was the use of too few water-injection wells.
“We look at some of these old historic waterfloods and they’re on three-to-one producer-to-injector ratios,” Barlow said. “That just doesn’t work—you don’t have enough injectivity into a single well to make that work.”
So what happened historically was operators would try to compensate for too few injection wells by injecting at too high a pressure.
Excessive spacing in well patterns was another issue.
“The patterns were too widely spaced on those old waterfloods—the distance between injectors and producers was just way too big,” Barlow said. “You could never have achieved a fully implemented waterflood in an economic timeframe.”
Low-rate wells were another challenge. Since the original Viking producers were vertical wells with low oil rates, they hit their economic limit at relatively low water cuts, which greatly reduced the recovery factors achieved.
In such situations, “you’re just going to leave a ton of reserves behind,” Barlow said.
Variable permeability also impeded the success of traditional Viking waterfloods with some floods failing because permeability streaks caused premature water breakthrough.
“If you look at some of the old waterfloods that were failures, they ended up having the water just cycle right through to some of the producers,” the Raging River vice-president noted.
Raging River is avoiding the past Viking waterflood problems in several ways.
Along with obviously recycling produced water, the company is sourcing saline make-up water from the Mannville Formation. This water is more compatible with the Viking formation than make-up water from freshwater sources.
“What we have is a few Mannville source wells that are working really well for us. We don’t seem to have any injectivity problems,” Barlow said.
Raging River is also maintaining a one-to-one producer to injector ratio. In other words, its preferred Viking waterflood patterns consist of horizontal injector-producer well pairs. This provides “great injectivity and you’re not ending up in an over-pressure situation,” Barlow told the PTAC-SRC workshop.
The company is also using tighter well spacing.
In the past, the spacing between injectors and producers was typically 400 metres. The inter-well spacing in the injector-producer pairs in Raging River’s patterns is between 100 and 200 metres.
Since horizontal wells have much higher productivity, they also have a much higher water cut, which will improve the potential recovery factor in areas under waterflood.
Horizontal wells also allow greater conformance, or distribution of injected water across the wellbore.
Instead of single-point injection into a vertical well, water is injected into a horizontal section with about 15–20 fracs, so conformance should improve. “Any conformance issues should be mitigated with diversion treatments isolating problem zones,” Barlow said.
Precision Drilling reports higher rig demand, but lower pricing
The Canadian Press
Published Monday, Apr. 24, 2017 8:20AM EDT
Last updated Monday, Apr. 24, 2017 8:22AM EDT
One of Canada’s largest oil and gas drilling companies is seeing renewed demand for its services but at lower prices.
Calgary-based Precision Drilling says it activated 17 rigs in its U.S. fleet, bringing the total to 56.
Precision Drilling also had 91 active rigs in Canada at the end of the quarter, up from 50 at the beginning of the year.
Revenue for the three months ended March 31 was up 14.6 per cent from last year, but Precision Drilling’s net loss also increased due to higher operating expenses and lower pricing for all its North American businesses.
Net loss was $22.6-million or eight cents per share, compared with $19.9-million or seven cents per share a year earlier. Operating loss was $12.9-million, compared with a year-earlier operating profit of $4-million.
Precision Drilling had $345.8-million of revenue, up 14.6 per cent from the first quarter of 2016. Cash provided by operations fell, however, to $33.8-million from $112.2-million.
Fri Apr 21, 2017 | 7:13pm EDT
BRIEF-Gensource reports strategy for third party project funding
Gensource Potash Corp:
* Gensource announces strategy for third party project funding & termination of Yancoal off take agreement
* Vanguard one project feasibility study is over 75 pct complete and remains on track to be finished in q2 2017
This visual timeline follows the long review of Canada’s proposed export pipelines: IHS Markit
By Deborah Jaremko
April 19, 2017, 1:29 p.m.
It has been seven years since a long-distance pipeline project departing western Canada has been completed, despite nearly 2.9 million bbls/d of capacity being proposed.
As IHS Markit outlines in the new Oil Sands Dialogue report Pipelines, Prices and Promises, given that projects have failed to materialize, “concern has been expressed that the review process has become increasingly uncertain, contentious, lengthy, and as a result, costly.”
The single greatest source of uncertainty in the pipeline review process in recent years has come after regulators have made their recommendations and when elected officials needed to issue a decision, IHS Markit notes.
A key example of this was the National Energy Board issuing approval to the Northern Gateway Pipeline, subject to 209 conditions, in late 2013. This was followed by federal approval under Prime Minister Stephen Harper in 2014, which was overturned by Prime Minister Justin Trudeau in late 2016.
At the same time Trudeau also issued a federal permit for the Trans Mountain Pipeline Expansion.
However, a pipeline receiving a permit does not mean the process is over, IHS Markit notes.
“Between permitting, construction and ultimately operation, many additional factors can affect project completion. These can include adhering to any number of conditions imposed by government, addressing public interests and interests of particular groups, and responding to requests for judicial review,” the report says.
“The story on these pipelines is not over, since none have been completed and the potential for additional delay exists.”
‘A reversal of fortunes’: Oilfield companies’ prospects set to rebound in the first quarter
Geoffrey Morgan | April 18, 2017 3:50 PM ET
CALGARY – A rebound in the oil and gas industry is poised to boost drilling and fracking companies, which have felt the pressure of the oil price downturn the longest, as analysts expect activity and pricing to rise 10 to 15 per cent over the coming year.
As oilfield services companies begin reporting their first quarter earnings this week, led by Mullen Group Ltd. on Wednesday, investment banks expect the sector to post surprisingly improved financial results.
CIBC World Markets analyst Jon Morrison said in a research note Tuesday that activity levels and operating margins of fracking companies, or pressure pumpers, should beat analyst expectations for all three Canadian providers – Trican Well Service Ltd., Calfrac Well Services Ltd. and Canyon Technical Services Ltd.
Morrison upgraded Trican’s stock to “outperformer” but maintained his target price of $6.75 per share. He also raised his target price on Canyon to $7.4 from $6.9, — the company agreed last month to a merger with Trican.
The analyst also predicted that oilfield service companies’ ability to hire enough people would become “a material challenge” and that “labour pinch points are starting to arrive across the energy value chain and we don’t believe that will alleviate anytime soon.”
Fracking companies, in particular, hit just 40 to 60 per cent of their hiring targets, Morrison said.
“Although the Canadian pressure pumping sector has faced immense duress over the past two years, look for partial reversal of fortunes in (the first quarter),” Morrison said.
Other oilfield services providers, like drilling companies, could expect better pricing for their services over the next 12 to 18 months because the average Canadian oil and gas producer expects its oilfield services costs to rise 10 to 15 per cent in 2017, Morrison said.
“Overall, we believe these figures better align with current market realities and may end up being light as select large ticket service costs are already up high double-digit percentages from the bottom,” Morrison said.
Similarly, AltaCorp Capital analyst Aaron MacNeil said that “by all measures, activity was really strong in the first quarter, perhaps not from a historical perspective but certainly from a sequential perspective.” He said that oilfield services providers are usually the last companies in the broader industry to experience a rebound.
“You always see activity first and you see pricing lag,” MacNeil said. He also said that while prices have risen for pressure pumping companies, the inflation has not affected all oilfield services providers equally.
Prices in the Canadian drilling industry, for example, are set in October before the busy winter drilling season begins. This year, however, Organization of Petroleum Exporting Countries (OPEC) agreed to an output cut after those prices were set and so oil prices rose without leading to a price rebound for drillers.
MacNeil said he expected prices drilling companies charge oil and gas explorers and producers would rise in the second half of 2017 as a result.
However, he also said in a research note the West Texas Intermediate benchmark oil price seemed to be range-bound in the low US$50-range and revised his 12-month target price on several oilfield services companies – including top picks like Precision Drilling Corp. – downward as a result.
Precision’s 12-month target price was cut from $10.25 to $9, Ensign Energy Services Inc. was cut from $12.50 to $11.50 and Shawcor Ltd.’s target price was cut from $47.50 to $42.75.
Saskatchewan strong: Geology, regulations and tech help oil and gas industry weather downturn, position for growth
Saskatchewan strong: Geology, regulations and tech help oil and gas industry weather downturn, position for growth
By Carter Haydu, By Pat Roche
April 18, 2017, 3:06 p.m.
Image: Joey Podlubny/JWN
The western Canadian oil and gas industry has taken it on the chin since global oil prices collapsed in late 2014.
Capital spending on conventional oil and gas development fell from a peak of $43 billion in 2014 to $21 billion in 2016. The well count has followed a similar decline, from 11,226 wells rig released in 2014 to 3,562 wells in 2016.
While Saskatchewan was hit hard by the decline in investment and activity, it fared a little better than its neighbour to the west. The well count declined by around 70 per cent in Alberta from 2014 to 2017, while Saskatchewan saw a decline of 55 per cent.
There are a number of reasons for Saskatchewan faring better than Alberta as prices dropped from highs of around US$100/bbl in 2014 to lows of $26/bbl in early to 2015 before recovering to jump around $50/bbl as 2017 began to unfold.
The first is geology, according to industry analysts at Scotia Waterous. A study by the investment house released in late 2016 shows six Saskatchewan oil plays are in the top 10 in Canada and the U.S. when ranked by profit/investment ratio.
When Scotia Waterous compared 55 U.S. and Canadian oil plays, Frobisher-Alida oil ranked second by profit/investment ratio and the Ratcliffe Play ranked third.
Viewfield Bakken oil, Upper Shaunavon oil and Viking oil ranked sixth, seventh and eighth, respectively.
Border Midale oil had the 10th best profit/investment ratio of the 55 plays.
All six plays break-even at a WTI oil price of US$40/bbl and some break-even at US$35, says Patricia Mroch, associate director with Scotia Waterous in Calgary.
The low break-evens are also among the best in North America, as are the payback periods, Mroch told a Canadian Society for Unconventional Resources (CSUR) Saskatchewan conference.
All of these plays are relatively shallow and cheap to drill compared to some of the deep shale plays, Mroch told the Calgary conference. She noted that it obviously helps that all six are oil plays.
The two top-ranking Saskatchewan oil plays on the list—the Frobisher and the Ratcliffe—are conventional Mississippian plays that don’t require fracture stimulation, Mroch said. “So they’re high quality. You have enough permeability and porosity that fracturing them actually doesn’t benefit you.”
In her presentation, Mroch noted Mississippian activity last year was strong across the entire trend in southeastern Saskatchewan—indicative of favourable economics even at oil prices below US$50/bbl.
She noted production from the Mississippian wells is stable with “very low” declines.
All six plays are being drilled horizontally, but fracturing is occurring as operators move into tighter parts of plays such as the Midale, Mroch said.
Scotia Waterous reported activity has been “very strong” in the Bakken-Torquay Field with Crescent Point responsible for about 85 per cent of 2015 wells and about 95 per cent of 2016 wells.
Bakken production has declined with reduced spending in the past 18 months while the smaller Torquay tight oil play has been growing as the economics are slightly stronger, according to Scotia Waterous.
“The reason people are still drilling in Saskatchewan is because those plays are still economic, and because it’s a stable environment politically,” Mroch said.
“People aren’t worried about the royalty regime changing like it has in Alberta. And in Alberta there are new carbon levies coming in. So there is some concern about how that’s going to affect the Alberta economics.”
Merger and acquisition activity has been strong in Saskatchewan compared to the rest of Canada, indicating the province is attractive to investors, she said.
Along with being cheap to drill, these plays can also be profitably produced at low oil prices.
Why Suncor Energy sees the oilsands as a strategic asset in the low-carbon transition
By Deborah Jaremko
April 17, 2017, 6:06 p.m.
Suncor Energy CEO Steve Williams. Image: Suncor Energy
Suncor Energy does not feel threatened by the world’s shift to lower-carbon energy resources.
In fact, the company sees its dominating position in the oilsands—a higher carbon source than conventional crudes—as a strategic advantage for its business through this decades-long transition.
This view is supported by expectations for continuing growing global energy demand, a massive, long-life resource base and the ability for technology to dramatically improve efficiency, Suncor says in its first-ever stand-alone report [download here] on climate released this week.
The report is in response to a shareholder resolution passed at the company’s 2016 annual general meeting.
Last year Suncor also added carbon risk as a principal consideration in its investment decision making process.
Leadership is needed to unify a global vision of an energy future that is progressive, yet practical, notes CEO Steve Williams in the report.
“We do not see a picture of doom and gloom for our industry. We do believe that oil demand will likely start to peak within 20-30 years at a level that is higher than today and although demand will decline thereafter, we expect oil will still be needed for decades,” Williams says.
“However, we do test our business strategy under a scenario where policy and technology cause oil demand destruction sooner and still see Suncor continuing to deliver value to shareholders.”
Suncor tests its oilsands and business growth strategy against three long-term energy scenarios, the company says, from one where fossil fuels remain dominant to another where rapid technological and societal change transforms the energy landscape.
“Under each of these scenarios, including our most aggressive decline in oil demand, we believe a substantial amount of oil will be required for decades. Meeting that demand at either low, or highly volatile, oil prices will be a challenge,” the report says.
Here’s an excerpt that describes the company’s position.
“In this environment, operators with short life reserves will find it increasingly difficult to finance exploration and development programs to replace declines, let alone grow production. The more commercially successful alternative energy sources become, the more capital they will draw from traditional energy markets, and the less likely we are to see substantial new crude oil supply come to market.
“While often characterized as being the oil basin most vulnerable to a low oil demand scenario, the very long operating life and low decline rate of our assets are, paradoxically, a major advantage under a scenario of either declining demand for crude oil and a correspondingly lower oil price, or an extended period of uncertainty and volatility in investment and commodity markets.
“Our long term reserve base presents minimal finding and exploration costs or risk. The nature of the resource requires high upfront capital investment to develop a project, but once the initial infrastructure is in place, the reservoir can be incrementally developed over a long period of time, without exploration risk, or the high capital requirements of a new project.
“Oilsands facilities are more comparable to manufacturing operations. Once operating, they are built to last 40+ years with a steady output. Production does not rapidly peak and decline, so each new incremental expansion results in production growth.
“Once high upfront capital costs are depreciated, a facility can continue to operate for potentially another 30 years with low operating costs and sustaining capital requirements only.
“Over the next 10 years, we believe technology will deliver the advances to make oilsands crudes both a low cost and a low carbon source of crude. The unique characteristic of the oilsands resource positions us to continue to deliver substantial value for shareholders under each of these scenarios.”