As expectations mount that next week will see Apache Corp. sanction its Kitimat LNG project, Yuryi Humber at Businessweek wonders whether Japan is on the cusp of going nuclear free. The country has been shutting down its 54 reactors to allow for safety and maintenance checks for months, he reports, and nearly 70 per cent of Japanese want to either reduce or eliminate atomic power entirely from the country's energy mix.

With or without the atom, though, Japan's power producers remain utterly dependent on imported fuel, as data compiled by the International Energy Agency illustrates:

China will undoubtedly be among the purchasers of Canadian LNG. While the country boasts substantial shale gas potential, "how quickly they bring that to market as well as at what cost is in question," Ken Fung, associate director, North American natural gas with consultancy IHS-CERA, told a Calgary crowd last fall.

In Japan, the expectation had been that a short-term spike in LNG demand growth prompted by last year's devastating earthquake would level out once nuclear capacity returned to normal. Indeed, the Federation of Electric Power Companies of Japan expects the country's nuclear capacity to increase to 23.6 per cent by 2019, up from 20.2 per cent in 2009. LNG is expected to account for slightly more than a quarter – 25.9 per cent – of the country's total generation mix by 2019. Those numbers will surely change if the wariness over nuclear energy persists. “Nuclear capacity reductions bode well for Canadian LNG exports," Fung said.

In the meantime, though, Japan's biggest oil and gas producer, Inpex Corp., is spending huge sums to develop its own liquefaction schemes. Its massive Ichthys LNG project in northwest Australia, which will cost no less than $34-billion to build and pump out 8.4 million tonnes of super-cooled gas annually beginning in 2016, was sanctioned last month.  Another $700 million was spent last fall for a 40 per cent working interest in British Columbia shale gas properties owned by Calgary-based Nexen Inc. The joint venture carries the potential to add yet more liquefaction capacity to Canada's West Coast.

It used to be that the West wants in. New Census figures from Statistics Canada underscore the fact that the balance of economic and political power has indeed lurched from Central Canada toward Saskatchewan, Alberta and British Columbia.

Canada's population grew 5.9 per cent between 2006 and 2011, the highest among G8 countries. Alberta had the fastest population growth rate among the provinces at 10.8 per cent, or nearly double the national average. Saskatchewan's population jumped 6.7 per cent on higher immigration and inter-provincial migration. British Columbia grew 7 per cent. See Statscan chart:

It's no coincidence that all three provinces are rich in resources. Yet the western shift is so pronounced that Alberta, B.C. and Saskatchewan together now have a greater share (30.7 per cent) of the Canadian population than Quebec and Atlantic Canada combined (30.6 per cent). See Statscan chart:

The new balance has thrown the Canadian social contract off kilter, John Ibbitson at the Globe and Mail surmises. Ontario no longer has a bounty to share with the rest of the country. "...[A]s globalization eats away at the province’s manufacturing base while rewarding the resource-based West, immigrants are starting to avoid the Great Lakes province," Ibbitson observes. "People and wealth are heading west."

Calgary in particular stands out as a growth story. The city's population jumped roughly 12 per cent between 2006 and 2011, thanks in no small part to its new stature as hub for white collar professionals.

The economic landscape has also changed. One need only look at the asymmetry of announcements made last week by Caterpillar Inc., which said it would close a locomotive plant in London, Ont., and Imperial Oil Ltd., which confirmed a $2-billion expansion plan at its Cold Lake project, for evidence of the hard realities that delineate the national portrait.

How does the country look in 2011 compared to 2006? As the population reached 33.5 million, Kelly McParland at the National Post says Canada has devolved into a two-trick pony, with an economy wholly dependent on government and natural resources. There is some truth to that. Alberta's oil sands have drawn job-seekers. Ditto for Saskatchewan's surging oil pools. Even Newfoundland and Labrador, where offshore development is progressing at a steady clip, registered a 1.8 per cent population bump, the first time since the mid-1980s more people have stayed on the rock than left for greener pastures. Precisely what that means for Alberta's labor-starved economy will become clear in the coming months.

A few oil and gas writers took note when in late January the United States' Energy Information Administration (EIA) drastically reduced its shale gas reserve estimates for the country. The venerable EIA revealed that (whoops) the U.S. has 482 trillion cubic feet (tcf) of unproven, technically recoverable shale gas reserves instead of the 827 tcf it had touted previously. Over at The Oil and the Glory blog, Steve LeVine was quick to put the EIA's revised estimates into perspective.

Now 482 tcf is still a lot of shale gas. But when the EIA drops its reserve estimates by 41 per cent, you can bet the oil and gas industry is asking itself questions. What does this mean for the plans to use clean-burning natural gas instead of gasoline to fuel more of our cars, trucks and SUVs?  Will the utilities be even more reluctant to switch from coal-fired to natural gas-fired power? And what does this say about the wisdom of exporting this valuable fuel overseas when there might not be as much of it for North America's use as was once thought?

It's that final question that is of most interest to firms like Shell Canada, Progress Energy Resources Corp. and Apache Canada Ltd. – all of whom are pursuing projects that would ship liquefied natural gas, sourced from British Columbia shale and tight gas basins, to Pacific Rim markets.

The EIA's new estimates are of interest to the companies betting big on B.C. shale and tight gas. That's because exploration in plays like the Horn River and the Montney in northeastern B.C. are at an even earlier stage than what's happening in Lower 48 basins like the Barnett and the Marcellus. If activity there is turning up production levels that are much less robust than what was originally thought,  could the same thing happen with Canadian shale and tight gas? If that were to happen, it would be bad news for producers in northeastern B.C. who have to convince Asian customers they have enough gas to meet their needs for 15 to 20 years.

But at least one firm is not impressed with the EIA's numbers. In a Monday research note, New York-based Bernstein Research took issue with the EIA's new estimate for the Marcellus play, which encompasses the states of Ohio, New York, Pennsylvania and West Virginia – among others. Of the most well-known U.S. shale gas plays, the EIA is particularly unkind in its new estimate of the Marcellus, which it now says has 100 tcf of reserves instead of 400.

Bernstein begs to differ, however. First, it notes that the EIA has yet to provide any details on how it arrived at the 100 tcf number, other than to acknowledge it got it from the United States Geological Survey's (USGS) recent work on the play. I can't link to the Bernstein note here, so you will have trust me on this, but by analyzing the initial production (IP) of every well drilled in the Marcellus since 2007, Bernstein has found several counties in the play where the average IP for wells was above 1.15 billion cubic feet (bcf). That's important because in determining the new reserve estimate for the Marcellus, the USGS used the 1.15 bcf per well average for the entire play.

Because higher IP averages means more gas would ultimately be recovered from the Marcellus,  Bernstein concludes in its note that the USGS and the EIA have erred in their revised estimates for the Marcellus. "We conclude that our assessment represents a more accurate view of the Marcellus resource than the USGS value embedding excessively conservative 1.15 bcf average wells," Bernstein's senior analyst Bob Brackett writes in the note.

Could the EIA be wrong in its revised numbers for other U.S. shale gas plays? Bernstein doesn't go that far in its note. But in casting doubt on the Marcellus figure, it's basically calling into question the entire 482 tcf estimate the EIA released two weeks ago.

But rest assured you haven't heard the last on this subject. Expect more competing shale gas reserve estimates to emerge in the months to come.

It's baaack. Or is it? Steep price discounts leveled against Canadian crude oil relative to West Texas intermediate in recent days have injected fresh life into a bet on differentials.

In a note this morning, FirstEnergy Capital analysts Martin King and Steven Paget predict Western Canada Select (the primary heavy oil marker here) could be trading at a US$30 discount relative to WTI by March.

But while the yawning split between WTI and its international counterpart, North Sea Brent, was driven last year by pipeline capacity constraints (that was the catalyst cited by traders, anyway, who turned the spread into the year's biggest bet), the emerging gap between WTI and Canadian light and heavy crude oil markers is not entirely related to transportation issues, FirstEnergy says.

"We do not see the recent widening of price spreads as being an issue surrounding lack of transportation capacity on Canadian crude oil export pipelines," King and Paget write.

Instead, they attribute the divergence to a series of short-term issues including refinery outages, and a resulting logjam of crude built up in the U.S. Midwest region. The commissioning of the highly anticipated Seaway pipeline reversal has also been pushed back from April to June.

Another factor: a "mind-boggling" increase in production of light oil from the Bakken formation in North Dakota. Daily output from the region exited 2011 north of 500,000 barrels. FirstEnergy expects another 100,000 to 150,000 barrels to add to the daily total before the end of the year.

All that oil, including new volumes from Colorado's Niobrara play, continues to make its way south and east, via barge, trucks, rail cars and pipeline, competing with Canadian output. (Incidentally, TransCanada's scotched Keystone XL pipeline had contracted to move at least 65,000 barrels daily from North Dakota to the U.S. Gulf Coast).

Meanwhile, more than 400,000 barrels per day of refining capacity is estimated to come offline in coming weeks. Maintenance issues, including a partial outage last week at BP's Whiting refinery, the largest consumer of Canadian synthetic barrels in the U.S., according to King and Paget, combined with rumored difficulties at Cenovus Energy's Wood River plant, have only added to the strain.

King and Paget do not think the growing spread between WTI and WCS, which gaped to US$35.50 yesterday, is here to stay. Barrel-on-barrel competition in the U.S. Midwest will subside, they believe, once refinery upgrades are completed, new rail takeaway capacity materializes and the Seaway reversal comes online. "Just like flying," the analysts write, "this bumpy turbulence will also pass."

Markets appear to be waiting for some catalyst capable of lifting natural gas from its current funk.

Bob Brackett of Bernstein Research believes one is on the way next week, when Apache Corp. releases its fourth-quarter earnings. The Houston-based firm reports Feb. 16. Calgary-based Encana Corp. and EOG Resources report the following morning.

In a note this morning, Brackett sees this clumping – Encana's reporting date appears to be a week delayed relative to normal – as evidence that a final investment decision on the multibillion-dollar Kitimat LNG proposal is in the offing.

Close observers of the LNG space wouldn't be surprised if that is the case. Apache has previously signaled that a decision on the export scheme would be made in the first three months of 2012.

The project, which would export five million tonnes of the super-cooled gas per year beginning in 2016 in its first phase and ramp up to 10 million tonnes by 2018, is the most advanced of several proposals taking shape on the West Coast.

Canada's National Energy Board last week approved a 20-year export license sought by B.C. LNG Export Co-operative LLC, a much smaller endeavor proposed by Houston-based LNG Partners and the Haisla. Shell, who just last week welcomed PetroChina as a 20 per cent shareholder in its Groundbirch shale gas property, is also rumored to be working on an export scheme.

Keep an eye on costs and watch for consolidation as plans for the region solidify. In addition, equity positions in the various LNG forays could yet be exchanged for sales contracts with Asian buyers. Such has been the case in Australia, Brackett notes, where Tokyo Gas, KOGAS, Cnooc Ltd. and Sinopec have all bought in to LNG projects in exchange for signing so-called "off-take agreements" with project developers.

In January, Alberta Oil published its annual C-Suite Awards issue. In this edition,  seven energy executives representing some of the best and brightest minds in the sector were profiled. (You can read all of the profiles here.)

Thursday night in Calgary, the magazine held it's annual C-Suite Awards gala with all the award recipients in attendance. What I found noteworthy in all the acceptance speeches was that every single recipient stressed how critical teamwork has been to their success.

While it's always a good idea to be gracious in victory, I don't think the comments were cases of false modesty. No senior manager – no matter how good they are at their job – can do it alone. It takes a great team to get great results. And based on what I heard from all the 2012 Alberta Oil C-Suiters, it's clear they are keenly aware of this fact. I guess that's why they've risen to the top of their respective professions.

But the teamwork comments weren't the only noteworthy things said by this year's C-Suite Award winners. Below are a few of the more notable quotes from the gala.

Steve Snyder (TransAlta) – CMA's Chief Executive Officer of the Year

In accepting his award, Snyder, who retired as TransAlta's CEO in January, said that events like the C-Suite Awards gala were an invaluable way to acknowledge the impact the energy industry – and the people who work in it – have on today's society.

We need to do more to celebrate this sector. So I'm very proud to stand up and celebrate the energy sector and the contribution it makes.

Robert Spitzer (Apache Canada Ltd.) – Top Government and Community Relations Executive

As chairperson of the Horn River Producers Group, Spitzer noted that consulting early and often with the people who live in northeastern British Columbia's Horn River area, and are affected by shale gas exploration, was vital in gaining local buy-in for the group's development plans.

If that's not done, you would end up with a lot of people not feeling too good. So there are two guiding principles to this – treat people the way you'd want to be treated and keep it simple. If you do that, it will all work out in the end.

Art MacNichol (Progress Energy Resources Corp.) – Top Chief Financial Officer

Natural gas producers have to be depressed as they watch prices for the cleanest burning fossil fuel sink below the US$3 mark. But MacNichol says there is light at the end of this very dark tunnel. And that light is coming from the likes of Progress Energy and other companies who are currently pursuing projects to export liquefied natural gas from British Columbia's West Coast to lucrative markets overseas.

This will unshackle B.C. gas from North American pricing. It's a very challenging period for those of us producing natural gas. But the future is very bright.

Canada's National Energy Board (NEB) has approved an export license for B.C. LNG Export Co-operative LLC to ship up to 1.8 million tonnes of the super-cooled gas per year for 20 years from British Columbia's West Coast at Kitimat. The project, a 50 per cent partnership between Houston-based LNG Partners and the Haisla, joins the Kitimat LNG venture sponsored by Apache Canada Ltd. as the second export scheme to win approval from the federal regulator in the last six months.

At least 13 parties have signed on to become members of the shipping collective, which plans to move its first tanker of LNG by 2014. No sales and purchase agreements have been signed with potential customers, although the co-op counts prospective buyers among its members. A final investment decision is expected on the first barge-based liquefaction train, estimated to cost $400 million, by April 15, Nathan VanderKlippe and Carrie Tait report at the Globe.

Market watchers are also expecting a decision on the much larger Kitimat LNG venture this quarter. That project would ship five million tonnes of LNG annually, or 700 million cubic feet per day, in its first phase to overseas markets. By 2018, plans call for construction of a facility big enough to pump out 10 million tonnes of the stuff each year, or a whopping 1.4 billion cubic feet per day.

Both projects are supported by growing supply projections from B.C.'s Montney and Horn River gas plays, as well as the promise of diversified markets at a time when North American natural gas, beset by surging supplies and mild weather, is trading at bargain basement discounts. In approving the export co-op, the NEB "recognizes that the forecast annual LNG demand growth in Asia provides a new opportunity for Canadian producers to diversify their natural gas export markets."

In addition, the board said the co-op would "allow smaller natural gas producers and marketers to participate in a market that otherwise would have been cost prohibitive due to the high, front-loaded costs associated with developing a liquefaction project."

Those costs could escalate quickly. The export co-op is smaller than its Apache-sponsored rival, and proponents believe they can keep a lid on inflation by building the initial train remotely on barges. Both projects will require specialized steel and engineering, however, which could lead to higher costs, according to FirstEnergy Capital analyst Martin King.

More than the co-op, the $5-billion Kitimat LNG venture must also compete for labor with the oil sands and federal shipbuilding contracts. Proposals in the works by Shell Canada and Progress Energy, plus those planned for the Gulf of Mexico and U.S. West Coast, will surely add to the strain. "People have to watch the cost side of the equation and factor that in to what they think prices are going to be, because you're looking at three or four years down the road before you can start to monetize the assets," King said in a recent interview.

Australia provides a case study in cost blowouts, with some LNG projects there as much as 50- to 70-per cent over budget. "Some of these are into the $20- or $30-billion range," King said. "That's a lot of money."

You can link to the NEB decision on the co-op here.

Are Republicans spooked by Northern Gateway? You might be inclined to say yes, given the pitch and frequency of pipeline-related commentary so far in the GOP primary race. Or is that just the sense one gets from watching Newt Gingrich, whose chances of actually reaching 1600 Pennsylvania Avenue are, as Konrad Yakabuski at the Globe put it yesterday, "sinking faster than the bids on a Tampa bungalow"?

Gingrich has certainly made Keystone XL, the fabled Gulf Coast link proposed by TransCanada Corp., his business. Where Mitt Romney has been diplomatic, Gingrich has been a shade light of bombastic. In a wild speech following his sound drubbing at the hands of Romney in the Florida primary, for instance, Gingrich implored Canada to "not cut a deal with the Chinese," Bryn Weese at Sun Media reported Tuesday.

It was a line the former House speaker was toeing 72 hours before his Florida no-show, at a Tampa-area retirement home of all places. "Right now the Canadians are looking seriously at a partnership with China," he told an assembled crowd that included David Weigel at Slate.

The suggestion that Gateway's fortunes will be decided by a firm handshake between Enbridge Inc. CEO Pat Daniel and, perhaps, Fu Chengyu, Sinopec's recently installed chairman (Reuters has an excellent profile of the man), will strike many who have watched the pipeline drama play out to date as a tad too simplistic.

Does Ottawa view Gateway and Chinese energy demand in general as a sort of trump card, an ace in the hole that might force Washington's hand on Keystone? Not according to Natural Resources Minister Joe Oliver. "I wouldn't call it leverage," he told assembled reporters at the Calgary Chamber of Commerce last week, "but we're always better off when you have more than one customer."

"Look, we have a very friendly, productive relationship with the United States," the minister added. "We expect that to continue."

Still, the diplomatic ante could be upped next week, during Prime Minister Stephen Harper's trip to China. The visit could result in a series of "co-operation agreements" between the two countries, Sneh Duggal reported yesterday at Embassy. Among them is a Foreign Investment Promotion and Protection Agreement, which Ottawa and Beijing have been haggling over since 1994.

Oliver describes the Sino-Canadian relationship as run-of-the-mill. "We need to diversify our customer base," he said recently. "They need to diversify their sources of energy." But it's clear China brings a stronger hand to the negotiating table in 2012 than it had in the mid-1990s. Indeed, one gets the feeling that the country is not so much feasting, but rather selectively nibbling from a buffet offering of Canadian energy assets. The latest crumb to catch the dragon's fancy is a 20 per cent stake in Shell Canada Ltd.'s Groundbirch shale gas property, bought for an undisclosed sum by PetroChina, in northeastern British Columbia.

Alberta Premier Alison Redford has a big idea. She calls it a national energy strategy. It’s an interesting, and for Redford, politically risky gambit: any talk of such a strategy brings back memories in Alberta of Pierre Trudeau’s reviled National Energy Program (NEP).

But Redford’s vision is no NEP – The Sequel. The premier views this strategy as one that would be driven by provincial, not federal, interests. The provinces would be setting the agenda, and it would recognize the provinces’ jurisdiction over natural resources without preventing them from co-operating on energy matters. It’s a tricky thing Redford is trying to pull off. But it’s noteworthy that normally parochial Quebec recently voiced support for the concept. “It makes immense sense,” Quebec Premier Jean Charest told reporters last month after meeting with Redford in Quebec City.

Getting provinces and territories with often widely different interests to sit down and hash out a coherent plan of attack with regards to energy won’t be easy. Yet Redford appears to have hit on something here. Industry leaders like Shell Canada’s president Lorraine Mitchelmore have long been beating the drum for a national energy strategy.

There now seems to be some political momentum for the concept, too, with British Columbia and Saskatchewan also backing Redford’s idea. If she can pull this off, the benefits could be immense for Alberta and Canada. With the provinces and territories united on big-ticket issues, a national energy plan could aid Alberta as it seeks to develop and export more of its oil and gas.

Alberta and Canada need more people like Redford bringing forth new ideas that could be game-changers. Keeping the status quo alive is not an option in the energy sector. Any jurisdiction that stagnates will drift into irrelevancy, bypassed by other regions that are more innovative and efficient. That’s why we need bright people thinking about (and pursuing) bright ideas. If the oil and gas industry and leaders across Alberta and Canada don’t foster innovation, the sector won’t evolve and North America will be living in the past when it comes to energy. That’s not good.

In an industry that is as volatile and has as many moving parts as this one does, one can never be certain what the future will look like. But that shouldn’t stop us from coming up with new ways and new technologies to shape that future. And that’s why big ideas and innovation are the focus of this issue of Alberta Oil. For the individuals, companies and organizations that work in the energy business, the future is now.

What a difference 10 years makes. A decade after PanCanadian Energy Corp. and Alberta Energy Co. were joined at the hip to create Encana Corp., at least one of the commodities that fueled the merger offers investors about as much certainty as a game of ring-toss at a small-town carnival.

Certainly there are as many wild cards at play. As Encana last week celebrated 10 years of operations – one imagines the occasion did not warrant champagne, what with the state of the firm's stock and so many vultures circling overhead – U.S. President Barack Obama was midway through a policy pirouette, announcing in his address to the nation that developing shale gas "will create jobs and power trucks and factories that are cleaner and cheaper, proving that we don’t have to choose between our environment and our economy."

Other choices are not so easily resolved. The Conference Board of Canada notes in its latest winter outlook this morning that U.S. economic growth could hit 2.7 per cent this year, up from 1.8 per cent in 2011, provided legislators in Washington find common ground on lower payroll taxes and other measures to stimulate short-term growth.

The outlook assumes Europe doesn't slip from its current precipice into recession, a shaky proposition amid continued disagreement over how to engineer a controlled collapse of Greece. "There are obviously huge downside risks to the current outlook, given the poor track record of politicians in Europe and the United States for dealing with their respective debt challenges," write Kip Beckman, principal research associate, and Paul Darby, deputy chief economist, with the Conference Board.

Scratch from your wish list, in other words, a short- or medium-term recovery in natural gas prices, at least one driven purely by demand. Even the ballyhooed production shut-ins announced last week by Chesapeake Energy Corp. and other gas titans – a development that has raised more than a few eyebrows on its own – offered only a "momentary floor" for prices, Bob Brackett of Bernstein Research told clients this morning.

The U.S. gas rig count remains above 750, and drillers targeting oil and liquids are increasingly producing so-called associated volumes of natural gas in spades. Brackett also calculates that one billion cubic feet of production curtailments is only enough to offset one degree of abnormally warm temperatures in the short-term. "That means one [billion cubic feet per day] of production curtailments need to occur for 4-5 months just to make up for January's warmth," he writes.

Producers are unlikely to exercise such restraint, Brackett concludes. He suggests that those companies that can stand to might even prolong the current price funk in an effort to starve industry weaklings, setting the stage for a round of consolidation in the fashion of Standard Oil and John D. Rockefeller. Brackett notes that the famed oilman, while keeping his thumb on prices, once quipped that a "good sweating" was "healthy" for Standard's rivals. Investors might wonder whether Encana, fresh from a year of asset juggling, could stand to lose a few more pounds.

As numerous companies look to advance liquefied natural gas (LNG) export projects on British Columbia's West Coast – with the aim to send the chilled fossil fuel to lucrative Asian markets – the conventional wisdom is that these companies need to worry about competition from the likes of Qatar and Australia.

But Canada's big neighbor to the south also has designs to export LNG, as producers there look to find attractive markets for all that unconventional gas they are extracting from basins like the Eagle Ford and the Marcellus in the Lower 48. In its weekly LNG supplement,  FirstEnergy Capital notes that Sempra Energy recently received approval to export LNG from its proposed plant in Hackberry, Louisiana. Sempra has been given the okay to export 1.7 billion cubic feet a day (bcf/d) of LNG to countries with free trade agreements with the U.S.

The Sempra project is one of seven export terminals being proposed in the U.S. (to see all of them, plus three Canadian projects slated for the B.C. coast, click on this link.) It's interesting to look at the numbers provided in the link. The three B.C. projects would export a combined 1.95 bcf/d, while the total for the American projects is 12.1 bcf/d. And that number doesn't include the 2.8 bcf/d export facility in Brownsville, Texas that Gulf Coast LNG Export LLC has applied to build.

Assuming all of these U.S. facilities are approved and built, (admittedly a dangerous assumption), where is all this LNG going to go? Only one of the U.S. export terminals is located on its Eastern Seaboard, the rest would be located on either the Gulf Coast or the West Coast. That makes it possible these terminals could target Pacific Rim markets –  just like their Canadian competitors.

Can three small Canadian LNG export schemes lock up long-term customers when those same customers could get it from bigger U.S. plants that have greater economies of scale? It's a fair question. And it's one that the likes of Apache Canada's Tim Wall and the other partners of the Kitimat LNG project must be asking themselves as they make a decision on whether to pour billions of dollars into an export terminal.

Applause rang out at the Calgary Chamber of Commerce as federal Natural Resources Minister Joe Oliver yesterday denounced Canada's regulatory apparatus as "unpredictable" and "needlessly complex." "Bad processes do not produce good environmental outcomes," he told a roomful of oilmen at an industry-sponsored cocktail event.

Away from the podium and his prepared remarks, Oliver promised broad changes to the system – both legislative and regulatory – before the year is out. He envisions a process with "enforceable" time lines, so that project reviews don't go on "forever." "The Mackenzie Valley gas pipeline project took nine years to be approved. Josyln North took six years. This is excessive."

Oliver's unvarnished enthusiasm for Alberta's oil sands is nothing new. Yet Stephen Ewart at the Calgary Herald wonders whether all the bluster and anxiety about "champagne socialists," as Oliver described opponents to Enbridge Inc.'s Northern Gateway project at one point yesterday, is for the best. Canadians are divided over the project, Ewart cautions, and opponents cannot be easily lumped under the same umbrella.

Oliver suggested major reforms lie ahead, promising "system-wide legislative changes, and lots of it."

He insisted that any reforms introduced to Canada's regulatory system are not directly tied to ongoing reviews of the West Coast pipeline proposed by Enbridge. But the two appear intimately linked. There was no mention, for instance, of the need for sweeping changes in a December 2011 report compiled by consultancy IHS CERA – along with the industry biggies, NRCan was surveyed for its views – that compared regulatory processes in Alaska, South Australia and Alberta. "I'm not commenting on Gateway," the Minister said yesterday, "but we're going to be looking at this before the Gateway project is completed."

Environmentalists are wary of such talk, Jeff Jones reports at Reuters. "We certainly want to see our government support the process that the National Energy Board allows, a process that allows all members of the public to have a say on a project that's of concern to them," Jennifer Grant, director of the oil sands program at the Pembina Institute, told the news wire.

Oliver is more sanguine, rattling off oil sands statistics and dismissing outright the suggestion that his government might undermine results of the Gateway review by tinkering with the process at its mid-point. "There are reviews ongoing all the time," he told reporters yesterday. "If we waited for all the reviews to be completed we would never act."