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There was a time when OPEC meetings actually moved global oil markets one way or another. Take last November for example. When OPEC decided it would not shut in production to support already softening world oil prices, markets reacted by driving down crude values dramatically. WTI went into the November 27 meeting at US$73.70. The next day it fell seven dollars a barrel, then continued a downward slide until it hit bottom at US$43.39 on March 17.
Volumes have been written about why OPEC did what it did last fall. Conspriracy theories emerged involving Iran, Russia and U.S. shale oil. There has been considerable conjecture about whether OPEC is still relevant, or whether the U.S. is the new Saudi Arabia as the world’s “swing producer.” OPEC member countries depend almost entirely on oil revenue to drive their economies. Were they mad? Can’t they do math? Maybe they were just kidding. Speculation about a different outcome at the June 5 OPEC meeting began immediately.
Well it’s no joke. On June 5, 2015, OPEC announced its quota would remain unchanged at 30 million b/d and world oil markets were going to have to sort things out on their own. In fact, former member Indonesia (which quit after becoming a net oil importer a few years ago) actually re-joined. Markets bounced around for a few hours before concluding nothing had really changed. WTI posted a slight gain on the day, up US$1.13 to close at US$59.13.
While WTI has recovered significantly from its March lows to trade in the US$60 a barrel range for the past month, OPEC’s announcement ensures there will be no intentional invervention by anyone to constrain supply. Nobody intends to voluntarily shut in any meaningul quanties of oil. So it’s back to the old oil forecast dartboard to figure out where prices will go in the last half of the year and into 2016.
The International Energy Agency’s most recent report sees global demand hitting all time record levels by the fourth quarter, a whopping 94.78 million b/d. This is a full million barrels a day more than the same period in 2014. Lower gasoline prices are having a predictable impact on U.S. fuel demand. The Energy Information Administration reported the highest petroleum product consumption in May since 2007. SUV sales are soaring while hybrid vehicle sales are tanking. The EAI predicted U.S. oil consumption would average 19.37 million b/d in 2015, up about 350,000 b/d from 2014 and over 400,000 b/d more than 2013. With lower gas prices triggering a rise in demand for bigger vehicles and the summer driving season upon us, these figures are probably low.
Similar increases in fuel consumption and vehicles sales are being reported in Europe where the combination of European Central Bank economic stimulus and lower fuel prices are causing what has until recently been considered a predicatable reaction by markets. Lower the price and consumers buy more.
It is the supply side that is causing commodity traders the greatest anxiety. Despite a collapse in the U.S. shale oil drilling rig count (642 on June 5, 2015, nearly 1,000 lower than last October according to Baker Hughes), U.S. shale oil production remains stubbornly steady. This can’t last and it won’t. But recent and accurate production figures are hard to come by with the latest data being three months old. U.S. oil storage inventory is falling fast now that there’s no money to be made holding physical oil for future sale. This was another media-manufactured crisis that never materialized.
Canadian bitumen production will continue to grow this year, the result of long-term oilsands investments reaching completion. This will happen again in 2016 and in 2017 when Suncor Fort Hills is scheduled to be completed, the last major greenfield oilsands project in the hopper. This could total as much as 400,000 b/d, good for those providing production services but of no help to global or North American oil markets. There are also some long-term projects in the Gulf of Mexico which will be adding production this year.
The global wildcards which will have the greatest impact on crude prices this year and next are Iran, Iraq and Libya. Iran is currently subjected to global production sanctions, while the other two are engaged in various forms of civil war and sectarian violence. Iran and Saudi Arabia, populated primarily by competing Muslim religions, are also engaged in a defacto struggle for control of the entire Middle East. This conflict has spilled over into Yemen.
Analysts have quite rightly pointed out that IF Iran reaches an agreement with nuclear inspectors and sanctions are dropped it could increase production by 1 million b/d or more in the next year; IF ISIS insurgents in Iraq give up and an outbreak of peace allows Iraq’s massive production potential to be safety unlocked; and IF all the people who hate each other in Libya were to make nice and take meaningful jobs working in the oilpatch to raise production; THEN a lot of extra oil could flood the market and depress prices.
But that is not going to happen anytime soon. Centuries of conflict and violence will not be resolved in 2015 or 2016 so the people of the western world can have cheaper transportation fuels.
This newsletter maintains its stated position since January 2015 that crude prices will continue to strengthen as the year progresses. U.S. shale production will fall more than people believe and U.S. oil demand will continue to rise. Because of major drops in drililng and spending worldwide and the stimulative impact of low prices, global supply and demand curves will cross sooner than most analysts believe.
But there will continue to be lots written about how oil prices will go down before they go up. Today’s hyper-competitive media reports everything whether it makes sense or not.
Besides oil prices, in Alberta the ‘patch has yet another level of uncertainty in the form of NDP Premier Rachel Notley’s promised royalty review. But other than scoping the terms of reference and perhaps populating some sort of panel, nothing will happen this year.
However, when centre-left governments decide to review corprorate fiscal regimes, there is no record in Canadian history of this being undertaken because the presiding politcians deeply believe corporations are paying too much. Nothing to look forward to here.
So for Canada’s beleagured oilfield services sector, the best plan of action is to redefine your definition of recovery. The worst is over, but it is not going to be like 2014 again anytime soon, if ever. The first quarter was dominated by fear from the price collapse and the second quarter was spring break up with nobody in a hurry to do anything. Canadian crude (Edmonton Mixed Sweet) closed at CA$73.29 a barrel on June 5, 2015. Services prices are down. This industry and this basin was built upon much lower oil prices. Expect gradual activity increases in conventional spending and drilling for the rest of the year.
So there’s going to be a royalty review. NDP Premier Rachel Notley campaigned on it and the people of Alberta voted for it. This issue is of great concern to Alberta’s beleagured oilpatch. It is unlikely Alberta’s new, left-of-centre government is reviewing royalties because they believe producers aren’t sufficientlly profitable.
The reality for Alberta’s oil industry is sobering. The NDP is in power for at least four years. The oil and gas is here. The assets are here. The people are here. Will the business remain competitive? Despite her campaign promises, Premier Notley keeps advising the oilpatch to be calm. Everything will work out, to quote the Premier, “A-OK.”
And it could. It really depends upon how the royalty review is conducted. Notley has promised public input, which would make it similar to the hearings the Stelmach PC administration held in 2007. There was no screening or stakeholder qualification to participate. Because Alberta’s oil is owned by everyone, every opinion mattered. All you needed was a pulse and a voice. Anyone and everyone was given their shot, 5 minutes for an individual and 10 minutes for a corporation or trade organization.
The industry participants universally presented mathematical arguments based on Return On Invested Capital (ROIC) and dwelled on arcane concepts such as investor confidence and international competitiveness. Meanwhile, the public talked about highly subjective defintions of “fairness” and how Albertans needed better health care, roads and seniors’ services. Be assured fairness got more media coverage than a globally competitive ROIC.
In September of 2007 Stelmach endorsed an “expert” panel report that recommended jacking up royalties by at least $1.4 billion a year. Titled “Our Fair Share”, it was a very political document long on rhetoric and light on statistics. The report was adamant that Alberta could increase royalties by about 20% on all categories of production and remain an attractive destination for investment.
While industry was devastated, the report was very popular because most Albertans believed oil and gas producers were unbelievably profitable, this business is easy and a a bigger cut for the government was harmless and essential.
Stelmach held his ground after oil and gas prices and the world economy collapsed in the latter half of 2008. The New Royalty Framework (NRF) became law January 1, 2009.
Two years later, when it was clear the “my fair share” based NRF was an unmitigated disaster in the face of the global economic crisis and new shale gas and tight oil discoveries across North America, another royalty review was undertaken by the Stelmach government. Called the Competitiveness Review, this took a completely different format. Joe Public was not invited. Instead, government and industry experts studied study various prospects from multiple juridications in terms of land cost, drilling and completion expenses, anticipated production and decline rates, and the full cycle return on invested capital.
The numbers were clear. Alberta was clearly not competitive under the NRF compared to other markets with similar geological opportunities. Changes were made in the second quarter of 2010. After nearly three years in the economic wilderness, Alberta’s oilpatch went back to work.
So the fact that the Notley government may review the royalty regime does not in itself mean the outcome is predetermined. In 2007 oil prices were rising, gas prices were high and industry activity was frantic. The economy was rocking. The argument even emerged that having an enlighted government slow down an overheated economy for its own good was sound public policy.
2015 is a different story. Oil and gas prices have collapsed. Unemployment is rising. House prices are falling. Oilsands projects are being delayed or cancelled. Producers and service contractors are reporting huge losses. Nobody sees oil anywhere near $100 again without major military conflict somewhere important, like the Strait of Hormuz. If public hearings on royalties are held anytime soon, it will be interesting to see who is going to publicly demand the oil industry pay its fair share when it is so patently obvious this essential business to Alberta’s economic success is struggling mightily.
This is not to say the oilpatch can relax. Far from it. Taxes are going up. Deficits will rise. Lots of tough times ahead no matter what happens. More uncertainty caused by a new, activist, left-of-centre government is not helpful. The political debate will surely escalate. In the Calgary Herald on June 8, 2015, three former NRF panelists were adamant their recommendations were sound and the government caved under intense oilpatch lobbying. Raising royalties was not about economics but political will.
That the NDP will clobber the industry when it is down is not certain. In fact, it makes no sense at all considering the state of investment and employment. But we’re reminded again by three of the 2007 review panelists this process is also about perception, not reality. Here’s hoping.
Due to a massive contraction of the market and relentless client demands for lower rates, service prices are down across the board. While there may be very little room to get better deals on manufactured components such as casing or valves or multi-industry items like diesel engines, service work – a combination of specialized equipment, expertise and expendables – is being priced much lower than it was in 2014.
While the exact number varies greatly from service to service, it is not unreasonable to conclude oilfield service field (OFS) margins have all but collapsed for every service provider not protected by robust, long-term contracts. In the slump of 2015, many service companies will be working for practice, not profits. In this market if you don’t work for less, you don’t work at all.
The outcome is not completely negative. The combination of reduced service costs and oil prices 40% higher than their lowest levels in the first quarter has more operators planning to pick up rigs and drill once road bans are off. The industry has a long history of making good money drilling oilwells at much lower oil prices than $100 a barrel. Almost forever in fact, except for a short period in 2008 and the last three years.
How did we do that? Everything cost less, much less. Like they do today compared to the heady days of 2014. Prices have corrected so more prospects make money with WTI at US$60 a barrel. There is work to do. The problem is if service prices rises and oil prices don’t, the work disappears again. It’s a precarious balance as the recovery unfolds.
The challenge for OFS managers is manufacturing an internal profit margin at today’s prices. This is a matter of long-term survival. Debt must be serviced and bank ratios must be maintained. Equipment must be repaired and replaced. At some point OFS must generate a positive cashflow that in some way compensates for the risk and services the capital investment.
There have been some cost reductions. There was a break on fuel created by collapsed oil prices but government is stepping in to eliminate that like when Alberta raised fuel taxes by $0.04 a litre on May 1, 2015. Everybody has gone down their supply chains to secure lower prices on everything from frac sand to chemicals to rope, soap and dope. Going from labour shortages to labour preservation has saved money on recruitment and training. Expense accounts, travel and discretionary spending have been cut or frozen. Capital expenditures have been slashed and maintenance on equipment not immediately required for revenue generation has been deferred. Some public OFS companies that pay dividends are reducing or eliminating them.
With money tight, companies may begin cannibalizing parked equipment for components to keep working equipment functional. This doesn’t ensure the survival of the company in the long run but it does conserve cash until things get better. When demand increases high enough to put all the capital assets back to work in the field, perhaps there will be enough cash around to put the equipment that was stripped back in operating condition.
But the elephant in the room is wages. While all salaried and hourly staff in most organizations from top to bottom have taken pay cuts (except those under contract like unions), and thousands of consultants have been released, there is still work to be done. If oil prices stay flat or don’t return to historic levels for years, as many believe will be the case (compared to where we’ve been, success would be WTI at US$75), then the amount of work will be capped by cost. OFS managers are going to have to retool their organizations to manufacture a margin at current service prices. Staff compensation is the only major expense centre with which this can be accomplished.
Wages for oilfield workers have gone off the charts in the past five years. This is purely a factor of market demand, not reckless management. The simultaneous development of the oilsands, conventional oil and gas, public infrastructure and the rest of the economy completely tapped out western Canada’s indigenous labour market years ago. The solution has been fly-in / fly-out workers from various parts of Canada and the U.S. and temporary foreign workers from all over the world.
The type of work the oilpatch does makes high wages essential. Many work in the middle of the night in the middle of winter in the middle of nowhere. What other incentive but high wages can there possibly be for capable people to want to do this type of work?
Last year compensation hit its zenith. A toolpusher on a rig drilling horizontal wells crept up to CA$1,500 per day or $300,000 per year if the rig worked 200 days. Directional drillers were a bit lower at CA$1,200 per day. Specialized sales reps in Calgary selling fracs and multi-stage packer assemblies routinely earned on the sunny side of $250,000 a year including bonuses and commissions. Including the fly-in / fly-out costs plus remote housing (“three hots and a cot” as it is called in trade slang), even entry level workers in the oilsands cost their employers the better part of $200,000 annually, welders and specialized tradesman earned much more. Productivity fell and costs rose to the point that major oilsands developers starting sourcing components in Asia, not North America.
This is all falling back into line out of economic necessity. The pay cuts that service companies have made to this point have been largely passed onto the customers. The challenge going forward will be to provide services at lower and competitive prices and generate a sufficient cash operating margin to service capital and equipment. This is going to be more difficult.
Companies need workers and workers need jobs. It is a symbiotic relationship. Be honest with your team. At the 2014 compensation rate there is no work. At reduced wages like we have now, there is some work. What is the price at which there will be more work? Do you know? Should you not figure it out and ask your staff if they are willing to work at those levels?
Another option for innovative employers will be to clearly align employer / employee goals to ensure success. Nobody has better control over variable costs that the people doing the work. If they can figure out how operate for a lower cost, incentives should flow. If employees doing service work can diligently bill more for expendables or travel time that might have been previously overlooked, incentives should flow. If employees can treat equipment better while operating it, thus reducing maintenance costs, incentives should flow.
While revenue and expenses will always be the margin drivers of operating margins, operating efficiency in OFS has continuously proven to be a major contributor to profitability. Doing it right the first time, on time and on budget, is always the most profitable way to do business.
Improvements in billing and cash collection processes can also help. Get the field ticket done right the first time and get in the front of the customer in days, not weeks. Accelerate the payment process. Get the cash in the bank. Eliminate credit risks. In this market, not getting paid promptly or not getting paid at all can be devastating, not just inconvenient.
This is a market in which innovative and capable managers working with engaged staff will do better than others. OFS owners and managers should start thinking outside of the box to manufacture a margin in a market in which it might not otherwise exist.
Only time will tell if he is right of course, but TD Securities Inc. Oilfield Services Equity Analyst Scott Treadwell was certainly the most optimistic on drilling activty for the rest of the year among three presenters at the Petroleum Services Assocaition of Canada (PSAC) Drilling Forecast lunch held in Calgary on April 30, 2015.
Sponsored by MNP LLP and moderated by your writer, the event also featured outlook presentations by Petroleum Services Association of Canada (PSAC) and the Canadian Assocaition of Petroleum Producers (CAPP). PSAC came in at 5,320 wells for year, down nearly half from 10,100 in October of 2014 and nearly one-third lower than a revised estimate in January of 2015. CAPP figured that 5,700 wells would be drilled this year, 4,700 less were drilled last year.
Hide the sharp objects. Nothing to look forward to for the rest of the year, even though oil prices seem to be making a steady recovery. WTI broke through US$59 the day of the forecast event, the highest price since December 11, 2014 and 36% higher than the six-year low set on March 17, 2015. The fact that more analysts believe the worst is over for oil prices and there have been major gains in the past few weeks clearly had no impact on how PSAC and CAPP see the rest of the year unfolding.
The ever-falling PSAC figure was carried in all the major media outlets starting later that day and was accompanied by colourful commentary about how awful things are in the oilpatch. Yet more proof that bad news sells.
TD’s Treadwell, however, took a different approach. He went through the cycles of Exploration and Production (E&P) company behaviour and crude oil markets and led the audience through a logical explanation of how and why the industry could drill 7,500 this wells this year, a figure approaching 50% higher than CAPP or PSAC.
If this figure is real, it means that once spring break-up ends, operators and their drilling and service providers are going to have to get to work for the last half of the year. To March 31, 2015, the Canadian Association of Drilling Contractors (CAODC) reports than only 2,075 wells had been drilled in what is historically the busiest quarter of the year. This is a 34% reduction from 3,135 wells in the first three months of 2014.
In the last nine months of 2014 the CAODC reported the industry drilled 7,785 wells of the 10,920 well total. For Treadwell to be correct there will be about 5,300 wells drilled from April through December. While still significantly lower than last year, that’s about 60% more activity in the second half of 2015 than PSAC or CAPP believe will occur.
The reason that there is such a divergence in outlooks is what Treadwell calls the operator tactic of “reduced information flow” whereby E&P companies intentionally don’t publicize their capital plans for the remainder of the year. The absence of a future order book for new business causes service prices to go down, not up. Layoffs and wage cuts occur which help service providers reduce the price at which they can operate. This may be brutal but with oil prices down 50%, it is also essential.
While some might call this behaviour predatory, the reality is the number of prospects that are economic to drill in times like this are a factor of commodity and service prices. If oil prices rise – which they have – and service prices fall – which they have – then prospects that were previously uneconomic under 2014’s service prices and Q1 2015’s oil prices start to make sense.
The big rise in oil prices is a huge factor. Treadwell pointed out that at the time of his presentation it was possible for producers to hedge (forward sell) Canadian light crude for 2016 at CA$77 a barrel. If prices hold, producer cashflow available for reinvestment could be up 25% next year, the reason he figures 8,500 wells could be drilled in 2016. Oil prices will rise because he figures that the decline in U.S. shale production and oil storage will continue, providing continuing support for crude in the months ahead.
But as is common in the oilfield services industry, managers must be careful not to confuse activity with success. While the idea that more wells will be drilled is comforting, it is only taking place because service prices have collapsed to what is approaching cash cost. In some ways, business in the last half of the year will be more about practice than profits. Unless equipment like new drilling rigs are under robust contracts guaranteeing day rates, market prices will not be high enough for many services to justify the massive capital investments that were required to make these assets available for service. At least not for now.
But the good news is more work means keeping employees engaged and helps sustain E&P customer production levels up. Cashflow from production is the number one driver of future oilfield service activity. Having OFS operators work at reduced prices to get the industry back on its feet while commodity prices improve is in fact an investment in the OFS sector’s future. Although it is unlikely most OFS owners, managers and shareholders actually view it that way.
Anecdotally, Treadwell’s prediction of improved activity right after road bans go off appears to be true. In talking to operators, drilling contractors and service providers, there are all manner of programs set to launch as soon as weather permits. Tourmaline Oil Corp., for example, announced in a news release on April 29, 2015, that it expects to be operating 16 drilling rigs by mid-June. Other operators are running the numbers on a play-by-play basis across the various geological horizons across the WCSB and are concluding that it is time to get back to work.
And drill they must. Oil and gas companies have to replace reserves and sustain production just to stay in business. Oil companies are like grocery stores; they are very profitable so long as they don’t re-stock the shelves. But they soon go out of business if they don’t.
So as we go back work – even at low prices – the oilpatch will be better for everyone if we actually have something to do besides complain to each and read the endless stream of bad news.That process will begin in the next few weeks.
The story was impossible to miss. Oil and pipeline haters used the internet (social media and email) to demand Tim Horton’s drop its paid advertising from Enbridge from their in-store TV information service. Based on 29,000 electronic signatures on an online petition, Tim Horton’s (now owned by global conglomerate Burger King) wilted and dumped the ads immediately.
This caused predictable outrage from all manner of commentators. The theme was that Tim Horton’s is the working oilpatch’s favourite coffee and donut outlet, but Tim Horton’s fears the online oil haters more than a negative reaction from its own blue collar clientele. This will be a news story for a day or so, another in a seemingly endless stream of corporations having their activities driven and shaped by organized but largely anonymous citizens who threaten their top and bottom lines if their behaviour isn’t satisfactory.
The problem is not the action, but the numbers. It’s a free society. Sign petitions. Issue news releases. Say whatever you want. The issue is the number of people – real or alleged – who are able to shape a corporation or society’s agenda without names, addresses or actual appearances.
If Tim Horton’s did indeed receive 29,000 real names from real people on this petition, this only accounts for 7/1000 of 1% of the population of Canada and the U.S., the major markets in which Tim Horton’s operates. It is 7/100 of 1% of the population of Canada. It is 7/10 of 1% of the population of Alberta, the province in which all that nasty bitumen is produced. This is nobody. Twice that many people were at the Women’s World Cup soccer game in Edmonton on June 6, 2015. This is not representative of anything but some corporate public relations hack at Burger King freaking out because one of its operating units got a bit of negative publicity.
While many in Canada regularly complain about the activities of Prime Minister Stephen Harper, at least he has a huge and legitimate mandate from Canadians to go about shaping the country compared to the Tim Horton’s fiasco. In the 2011 election over 5.8 million Canadians voted for the PCs and nearly 15 million people or half the population voted. These are the sort of numbers that should be required to change direction of a society or civilization, not 29,000.
Which is the root of the problem. Corporations and politicians are becoming increasingly sensitive to increasingly smaller groups of people who have figured out how to use the internet to advance causes. Canada’s bruised bitumen producers and pipeline operators must figure out how to fight back and separate hijack tactics from legitimate public concern or dissent.
The costs of everything associated with bitumen recovery have skyrocketed in the past decade according a report by Calgary investment banker Peters & Co. Limited and reported in the June 4 edition of the Daily Oil Bulletin. Drilling and completing SAGD well pairs now costs $8 to $14 million compared to half that amount ten years ago. Shipping costs using crude-by-rail are rising. Peters found that operating costs for mining operations last year were up to $45 a barrel, more than double $20 in 2004. Construction of a new oilsands mine costs $100,000 per flowing barrel, twice what it was early last decade.
The growth in in-situ costs development and operating costs has been less aggressive. Peter’s figures operating costs are now $19 a barrel compared to $14 in 2004, but a big part of the price break might be coming from lower natural gas prices. Construction of new SAGD projects are coming in at $40,000 per flowing barrel, more than double the $18,000 figure from 2004. Some projects are currently running as high as $60,000 per flowing barrel.
Cenovus Energy Inc.’s Foster Creek operation is described by Peters as “one of the best overall assets in the oilsands.” However, even Cenovus was hard-pressed to generate netbacks on bitumen production of $5 a barrel in the first quarter of 2015. Including sustaining capital, its free cashflow would have in fact been negative.
The report was meant to highlight the squeezed economics of bitumen development in light of the pending royalty review promised by Alberta’s new NDP government. The collapse in oil prices has triggered a subsequent collapse in bitumen royalties paid to the Alberta government which achieved record levels in 2014. Peters wrote, “Longer term, the overall royalty payments form the oilsands will be higher of volume growth can remain on track; and we believe it will be very important for the government to work with industry to incentivize future growth in the development of this resource.”
This was an exciting business to be in, at least for a while. That was the construction of crude-by-rail transloading facilities in the major producing areas of western Canada so producers could overcome pipeline bottlenecks and get their product to market. Hundreds of millions of dollars poured into the business as capacity was added at breakneck speed. With crude seemingly stable at US$100 a barrel or more, the higher cost of shipping by rail was easy for producers to profitably absorb.
Well that was so two years ago. With oil prices down and pipeline systems being de-bottlenecked across North America increasing capacity, this is now a tough business. According to the National Energy Board, oil shippers exported only 119,755 barrels of oil by rail each day in the first quarter of 2015, down 24% from 158,532 barrels per day in fourth quarter of last year and 28% less than 165,254 barrels per day in the first quarter of 2014. Ouch. Loading capacity is clearly overbuilt.
So taking its lumps on a bad investment, Canexus Corp. sold its Bruderheim transloading facility to Cenovus Energy Inc. on June 4, 2015, for $75 million, about 20% of the $375 million it cost to build in 2013 and 2014. Including the land that figure could be as high as $500 million, leaving Canexus with only pennies on the dollar from its total investment. Borrowings to build the facility had been putting pressure on Canexus’ balance sheet. Cenovus reported it only shipped an average of 13,000 b/d of crude by rail in the first quarter, most of it through the Bruderheim terminal. Cenovus said that it can ship oil by pipe at $7 to $10 a barrel while rail costs $15 to $18 per barrel, depending upon destination.
A FirstEnergy Capital report indicated that the Imperial Oil / Kinder Morgan transloading facility near Edmonton is designed to ship up to 210,000 b/d via unit trains and would cost about $425 million to build.
If you’re worried about where you can make money drilling for oil once Alberta’s royalty review is underway and completed, Saskatchewan Premier Brad Wall has invited E&P companies to consider investing in Saskatchewan. In a speech in Weyburn in late May Wall said, “We like where royalties are at. We want to tell the industry, whatever may be happening in the rest of the country, they can expect royalty stability here.”
Looking back in history, it was always Alberta that had an attractive fiscal regime for oil and gas development while Saskatchewan and British Columbia would periodically shut down activity due to the aggressive royalty and taxation policies of various NDP administrations. Now Saskatchewan and B.C. both offer competitive investment regimes and Alberta is the one wondering if the fiscal regime is appropriate.
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