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OIl prices and exchange rate down – bad and good for Saskatchewan

October 15, 2014
For 2014-15, when considering the provincial budget assumptions, it is estimated that :
• a US$1 per barrel change in the average WTI oil price results in an estimated $20 million change in oil royalties;
• a 1 U.S. cent change in the average value of the Canadian dollar results in an estimated $31 million change in non-renewable resources revenue.
Note, this is a full-year average and based on production amounts not deviating either.
The 2014/15 Saskatchewan budget was based on:
  • WTI oil prices are forecast to average US$94.25 per barrel in 2014-15
  • Exchange rate of 91.50
Today:
  • WTI is lower than forecasted at US$82.31 per barrel (not good for Saskatchewan)
  • Exchange rate is lower than forecasted at 88.31 (but this is good for Saskatchewan since we sell our oil and potash in US dollars and thus realise higher revenues)
Eric

Crude oil in U.S. slides most in 17 months on growing supply

Crude oil in U.S. slides most in 17 months on growing supply
Moming Zhou and Mark Shenk
Bloomberg News
Published Tuesday, Sep. 30 2014, 2:29 PM EDT
Last updated Tuesday, Sep. 30 2014, 2:31 PM EDT
West Texas Intermediate crude slid the most in 17 months, while Brent had its steepest drop in a year, as ample supply shielded the market from the risk of disruption as a result of the conflict in the Middle East.
Futures slumped as much as 3.9 per cent in New York and 3.1 per cent in London. OPEC oil production increased in September, led by a rebound in Libyan output to the highest level in more than a year, a Bloomberg survey showed Tuesday. Both benchmarks are poised for their biggest quarterly decline in more than two years. WTI may approach $90.63 after breaking below $93 and $91.50, according to Bloomberg First Word oil strategist Eric D. Pradas.
“We are going to continue to see lower prices as we go forward,” said Tariq Zahir, a New York-based commodity fund manager at Tyche Capital Advisors. “Fundamentally we are just very well supplied. The dollar continues to get stronger and it’s adding pressure to oil.”
WTI for November delivery fell $3.18 (U.S.) or 3.4 per cent to $91.39 a barrel at 1:31 p.m. on the New York Mercantile Exchange. Prices have lost 13 per cent this quarter, the most since June, 2012. The volume of all futures was 51 per cent above the 100-day average.
Brent for November settlement slid $2.46 or 2.5 per cent to $94.74 a barrel on the London-based ICE Futures Europe exchange. The contract fell as far as $94.24, the lowest intraday since June, 2012. Volume was 11 per cent above the 100-day average. Prices have decreased 16 per cent this quarter. WTI was at a discount of $3.32 to Brent on ICE, compared with $2.63 Monday, which was the narrowest close since August, 2013.
Third Month
Oil is set for the third consecutive month of losses as supply gains offset the U.S.-led military campaign against Islamic State. Brent is down 8.5 per cent in September, compared with a 5-per-cent retreat for WTI.
“It’s the quarter end and a lot of hedge funds are pulling money out of the market,” said Carl Larry, president of Oil Outlooks & Opinions LLC in Houston.
Reformulated RBOB gasoline futures slid 4.5 per cent to $2.576 a gallon on the Nymex, heading for a quarterly drop of 16 per cent. The October contract expires Tuesday.
“The weakness in the expiring RBOB contract is the primary driver today,” Stephen Schork, president of Schork Group Inc. in Villanova, Pa., said by phone. “The secondary driver is the end of the quarter, which leads to book squaring. A tertiary reason is the strength of the dollar, which always weighs on commodity markets.”
Reduced Positions
Speculators reduced their net long positions on WTI by 4.8 per cent in the week ended Sept. 26 to 193,965 futures and options combined, according to the Commodity Futures Trading Commission.
Oil also followed declines in other commodities as the Bloomberg Dollar Index climbed to 1,073.81, the highest since 2010. The Bloomberg Commodity Index fell 1.3 per cent. A stronger dollar reduces commodities’ investment appeal.
U.S. crude stockpiles probably expanded by 1.5 million barrels last week, a Bloomberg News survey showed before an Energy Information Administration report tomorrow.
U.S. crude stockpiles may have climbed last week as refineries started conducting seasonal maintenance. Plants typically schedule planned work for September and October, when they move from maximizing gasoline output to producing winter fuels.
‘Continuous Decline’
“What we are seeing is a continuous decline since the highs in June,” said Harry Tchilinguirian, BNP Paribas SA’s London-based head of commodity markets strategy. “We have not only financial deleveraging, but also physical surplus in the market. The dollar is going to be dominating.”
U.S. domestic production rose to 8.87 million barrels a day in the week ended Sept. 19, the most since March, 1986, according to EIA estimates. A combination of horizontal drilling and hydraulic fracturing, or fracking, has unlocked supplies from shale formations in the central U.S.
U.S. output gains are pushing out imports. Crude oil shipments to the U.S. fell 1.24 million barrels a day to 6.87 million in the week ended Sept. 19, the lowest level since May.
“Our reduction of imports is the same as an increase of supply to the world,” said James Williams, an economist at WTRG Economics, an energy-research firm in London, Arkansas. “The supply-demand fundamentals favour lower oil prices. A lot of speculators are getting out of long positions.”
Libyan Output The International Energy Agency said earlier this month that higher exports from Libya and booming U.S. production “deepened the overhang in crude markets and overshadowed any lingering worries of potential output disruptions in Iraq.”
Libya’s oil production was at 900,000 barrels a day, unchanged from yesterday, according to National Oil Corp. The country is working to restore crude output after a year of unrest reduced it to the smallest producer in the Organization of Petroleum Exporting Countries at one stage.
The U.S. and its European and Arab allies have conducted thousands of air missions against Islamic State militants in Syria and Iraq.
In northern Syria, Islamic State’s offensive against the town of Kobani sparked an exodus of tens of thousands of Syrian Kurds, raising concern that the conflict would widen. Tensions increased Monday after errant shells fired by Islamic State militants landed inside Turkey, injuring five people, Turkish Kurdish officials said.

Sanctions miss Russian oil

25 Sep 2014
Calgary Herald
ALEXANDER PANETTA THE CANADIAN PRESS
Sanctions miss Russian oil
So far, at least, Canada hasn’t targeted sector
NEWYORK— For all its much-touted toughness in imposing economic sanctions against Russia, Canada has been significantly more timid against one particular target: the oil industry.
A database of sanctions compiled by The Canadian Press suggests Canada has been almost three times less likely to penalize Russian oil companies than the United States.
The Harper government has imposed economic penalties against five Russian oil companies, compared to 13 firms targeted in that same sector by the U.S.
That’s despite the fact that in its vast array of more than 175 sanctions targets, Canada has been as tough as the U.S. — if not tougher — on other segments of Russian society, including private citizens, the defence industry, mining, and financial-services companies.
The oil and gas sector is a clear statistical exception, representing about 13.8 per cent of Canadian sanctions against companies imposed during the Ukrainian crisis.
By way of comparison, the proportion is about 29.5 per cent in the U.S. and 20 per cent in the European Union.
Also, four of Russia’s largest oil companies and its dominant pipeline company have faced sanctions in either the U.S., Europe, or both: Rosneft, Lukoil, Surgutneftgas, Gazprom and the state-run pipeline monopoly Transneft.
Not one of them has faced such measures from Canada.
In an interview, Canada’s industry minister said he hasn’t heard any complaints from the opposition or regular citizens about the approach to sanctions.
“There has been none of that,” Industry Minister James Moore said. “There’s been a unified Canadian understanding that the position of Stephen Harper is the correct one, morally.
It won’t be without its frustrations for some people who have had long business ties with Russia — but certainly some things are more important.”
But when asked whether the government might follow the U.S. with sanctions against influential Vladimir Putin ally Igor Sechin and Rosneft, the No. 1 Russian oil company that has Sechin as its chairman, Moore said: “I don’t have any comment on that.”
The Canadian government is on the international stage this week promoting its robust response to Russia’s intervention in Ukraine, as Prime Minister Stephen Harper makes it one of the themes of his address to the United Nations General Assembly.
Canada has, in fact, imposed more sanctions overall than either the U.S. or Europe. The Canadian Press compiled a database that shows Canada with 175, not including several against more amorphous entities like “the Federal State of Novorossiya,” which is also on the Canadian list.
As for why Russian oil is so scarce on that same list, one academic who has researched the geopolitical reach of Russia’s oil industry says there might be an extremely simple explanation: human oversight.
David Detomasi of Queen’s University says Canadian interests there are relatively minor. They’re mostly limited to providing logistical help with extraction — and don’t extend to actual drilling or ownership stakes, which American oil companies actually do have there. Exxon Mobil has just had to pause drilling in Russia’s Arctic because of American sanctions.
“Since we don’t have a huge amount of interests in Russian oil,” Detomasi said, “it could simply be something that hasn’t been attended to yet.”

49 North Resources Inc. provides a technical update and 2014/15 outlook on Allstar Energy Limited

49 North Resources Inc. provides a technical update and 2014/15 outlook on Allstar Energy Limited

 

SASKATOON , Sept. 25, 2014 /CNW/ – 49 North Resources Inc. (“49 North” or the “Company”) (FNR.V) provides a technical update on the oil and gas properties of Allstar Energy Limited (“Allstar”), its 100% owned subsidiary, with operations in south western Saskatchewan . As well, an outlook on some of its activities for the 2014-15 period are provided, which are expected to achieve some important milestones for the Company. Field optimization and production plans include: the completion of a water disposal well at Riverside , plans for a water disposal well at Red Pheasant, a natural gas well to provide power, continued vertical well programs and the initiation of a horizontal drill program into the Success formation at Riverside.  The combined programs are designed to see economic production from up to 15 wells in the two fields with additional revenue from disposal of third party water at the Riverside disposal facility.

Riverside

As discussed in previous news releases, Allstar completed a 6 well drill program in December of 2012 and January of 2013 at the Company’s Riverside Project near the town of Leader in south western Saskatchewan , with all 6 wells encountering the oil bearing Success formation.  Three of these six wells were drilled in the south western portion of the land holdings.  These three wells intersected as much as 45 meters of gross pay oil bearing Success formation.  The remaining three wells were drilled in the north eastern portion of the land holdings, targeting an up dip extension of the basin, and encountered 8 – 12 meters of the oil bearing Success formation.  Once completion operations commenced it became apparent that the wells had poor casing cement over the production zone, as indicated by high water cuts experienced during production, which was not consistent with production from the same formation at the nearby existing well.

When down-hole bond logs were completed the results showed poor and irregular cement bonding between the production casing and the formation in all six of the wells.  While the Company is confident all six wells can be productive, the resulting high water cuts experienced in completions of three of the wells warranted shut in until water disposal facilities are available on site due to the high cost of 3rd party transport and disposal. Remediation through down-hole cement squeezing will be performed with the continuation of completion operations once a water disposal facility is in place, which is scheduled for completion later this fall.

The Company signed a binding letter of intent (see news release February 12, 2014 ) with Canada Zhongan Energy Investment Ltd (“Zhongan”).  In accordance with the agreement, Zhongan advanced $2,000,000 for the drilling and completion of two vertical wells into the Success formation at Riverside.  These wells, 10-4 and 9-4, were initially completed in May 2014 , following a new cementing protocol.  Cement bond logs completed after drilling showed that the new protocol was effective in providing proper isolation of the production zone.

Initially these new wells were perforated in the lower Success formation to test un-stimulated production and brought on production for a short period of time.  These wells were then also perforated in the upper Success formation to test if incremental production could be achieved by mingling production zones.  The Company also performed a chemical flush at 10-4.

Concurrent with the chemical treatment at 10-4, a 20 ton CO2 frac on the 9-4 well was initiated with a view to testing fracture stimulated production.  Due to an unexpected equipment failure, this program was not completed as planned, with the equipment failing before the rock could be fractured.  In an attempt to remediate this well in the short term, a chemical flush was performed to clean out the perforation from the failed fracture treatment.  While this flush was successful in cleaning out the perforations, low inflow rates led to the Company suspending production from the well until further evaluations were conducted on the neighboring 10-4 well.

In late July, the Company successfully completed a 20 ton CO2 frac at 10-4.  This well has been producing at a restricted rate of 20 – 35 barrels per day since the frac.  The Company, along with partner Zhongan, is currently scheduling to complete a 20 ton CO2 frac at 9-4 this fall.  Once this program is completed Zhongan will have the option of proceeding at its discretion under the terms of the February 2014 agreement.

In late June of 2014, the Company, with its joint venture partner Westcore Energy Ltd., drilled a water disposal well at location 4-9 at Riverside . The 4-9 location was chosen for a number of reasons, including positive seismic indicators (Success oil horizon was confirmed while drilling), proximity to our 100% owned pipeline to the Trans Gas Bayhurst natural gas storage facility, all weather road access and proximity to our existing wells.

The disposal well is currently perforated in the Birdbear dolomite/limestone porosity beneath the Success formation and is awaiting a chemical wash to clean the perforations of drilling mud.  Once surface facilities are installed, the Company should benefit in cost savings of approximately $25 per barrel of oil produced.  Additionally, the Company will be in a position to add disposal revenues from third parties operating in the area.  Allstar is currently in discussions with a senior heavy oil producer operating on adjoining land regarding the disposal of water produced from its operations.  Allstar has been working closely with this heavy oil producer in the development of its work program and is encouraged to have a major industry player operating on the adjoining lands.

The Company has also commissioned a pressure truck which will serve the dual purpose of hauling water from production sites to the to-be-completed water disposal facility and allow pressure loading of wells without the need of third party contractors. With a truck on site at all times production should be enhanced through loading with higher frequency at substantially lower cost. The truck has been acquired with systems engineering and design currently underway.

Production continues at the Company’s original Riverside production well, 16-4.  Allstar opened the well in June of 2012 and has produced in excess of 25,000 barrels at an average rate of 25 – 30 barrels per day.  This well has experienced a very low to non-existent decline rate since being turned on in 2012.  The Company is modeling its current completion and production rate methodology after 16-4 given the successes experienced with this well.

Extensive research of the Success formation of south western Saskatchewan , combined with industry activity in the greater Riverside area, leads Management to believe that the Riverside Project is an excellent candidate for horizontal drilling and multistage fracturing.  Much like the work done by Allstar in the Viking field near Kindersley, Saskatchewan in 2010 – 2012 where the Company was on the leading edge of development of that pool, Management is now confident that similar techniques can be applied to the Success formation.

Also similar to activity in the Viking field, where an industry major helped lead the way in developing drilling and completion techniques, Penn West has recently completed a number of horizontal multistage frac’s in their Success formation project north of Riverside.  Results from these activities, while variable, have shown production results in excess of 80 – 100 barrels per day of production over periods greater than two years.

At 16 wells per section spacing, the Company’s current seismic data indicates that there are in excess of 30 potential horizontal locations within the four most south western sections of the Riverside Project encompassing current operations. The total Riverside Project land package consists of 25 sections.

Red Pheasant

Production at Red Pheasant was re-initiated in August of 2014 at three of the six shut-in wells.  These wells were all producers at the time that they were shut in due to low oil prices (high heavy oil differential) experienced shortly after being brought online.  Upon re-initiation, production results have surpassed the Company’s expectations.  While still early in their production cycle, the Company is very encouraged for the viability of the Red Pheasant field at current heavy oil pricing.  The wells are moving significant amounts of formation sand along with the oil, which should work to further open the formation allowing for more oil inflow.

The Company also perforated and pump tested one of the two standing cased wells drilled in late 2012 in the south western portion of the Red Pheasant land package.  Unlike the other producing wells at Red Pheasant, this well exhibited a high water cut.  While highly prospective given the oil produced from the well during the pump test, the well has been temporarily shut in until water handling facilities are put in place.

Following a 90 day production test on the three wells currently producing at Red Pheasant, the Company plans to re-initiate production at two other shut-in wells and pump test the other standing cased well. 3-dimensional seismic shows that the majority of the Red Pheasant land package is favorable for Manville oil and will continue to be evaluated for future drilling programs.

2014/2015 Plans

As discussed above, the Company has significant plans for field optimization at Riverside.  The addition of a water disposal facility, along with owning and operating a pressure truck should allow for all of the wells drilled to date to operate economically, regardless of the water cut realized with production. As the water disposal facility is completed, the Company intends to turn on and/or finish completions on the wells that are currently shut-in or standing, adding six wells to our existing producing well count of two.

Once the disposal facility is operational, optimization plans will shift to having our 100% owned natural gas pipeline tied into the Trans Gas storage facility and the drilling of a natural gas well.  This will allow the Company to power its wells and heat its production and disposal tanks with natural gas rather than propane, resulting in significant operational cost savings.

At Red Pheasant, the Company intends to convert the lowest production rate existing well into a water disposal well.  This will allow for the completion of the recently pump tested (high water cut) well and the other standing well, presumed to be of a similar nature, taking the total well count at Red Pheasant to seven.

Completion of this combined program should see the Company producing from 15 wells in two fields, along with additional revenues from disposal of third party water at the Riverside disposal facility.  The anticipated total cost of the field optimization and production plan is approximately $3,000,000 , which will be funded from a combination of production revenues, the proceeds of the ongoing 49 North rights offering and continued cash flow from 49 North’s portfolio of investments.

These steps, combined with the drilling of additional vertical wells are designed to optimize a stable base of production in both fields, and further delineate the Riverside field in anticipation of a future horizontal drilling program.

The Company’s current combined total production is approximately 120 barrels per day, based on field estimates.

49 North is a Saskatchewan focused resource investment company with strategic operations in financial, managerial and geological advisory services and merchant banking. Our diversified portfolio of assets includes direct project involvement in the resource sector, as well as investments in shares and other securities of junior and intermediate mineral and oil and gas exploration companies. Additional information about 49 North is available at http://www.sedar.com.

Forward Looking Information: This release contains forward-looking information within the meaning of applicable Canadian securities legislation. In particular but without limitation, this press release includes references to discovered and undiscovered oil and natural gas resources and Allstar’s future drill program. There is no certainty that any portion of the resources will be discovered. If discovered, there is no certainty that it will be commercially viable to produce any portion of the resource. There is no certainty the drill program will be fully or partially completed. Forward-looking information involves known and unknown risks, uncertainties and other factors that may cause actual results or events to differ materially from those expressed or implied by such forward-looking information, including the availability of adequate and secure sources of funding to complete, equip and bring the new well on-stream, prevailing commodity prices and the performance of 49 North personnel. In addition, the forward-looking information contained in this release is based upon what management believes to be reasonable assumptions. Readers are cautioned not to place undue reliance on forward-looking information as it is inherently uncertain and no assurance can be given that the expectations reflected in such information will prove to be correct. The forward-looking information in this release is made as of the date hereof and, except as required under applicable securities legislation, 49 North assumes no obligation to update or revise such information to reflect new events or circumstances.

Neither TSX Venture Exchange nor its Regulation Services Provider (as that term is defined in the policies of the TSX Venture Exchange) accepts responsibility for the adequacy or accuracy of this release.

SOURCE 49 North Resources Inc.

Contact:

49 North Resources Inc., Tom MacNeill, President and Chief Executive Officer, 306-653-2692 or ir@fnr.ca

Canadian oil producers thriving with their big-box business model

Canadian oil producers thriving with their big-box business model

Peter Tertzakian

Special to The Globe and Mail

Published Wednesday, Sep. 24 2014, 5:00 AM EDT

Last updated Wednesday, Sep. 24 2014, 5:00 AM EDT

 

There are many ways to run a business. For example, purveyors of luxury goods don’t sell big volumes, but make money on wide margins. Department stores don’t make as much profit, but sell more stuff. Innovators rely on technology for their value. Fast followers copy the innovators.

Here is a business model we all know: Discount prices, take share from smaller players, create new channels of distribution, and gain cost efficiencies through scale. “Big-box” stores like Wal-Mart, Costco and Best Buy are champions of these market-bulldozing tactics.

The approach sounds a lot like today’s Canadian oil and gas industry.

Becoming a high-volume price discounter wasn’t a conscious, collective strategic business decision. Most would say that the big-box model was imposed on Canada’s industry because of price differentials resulting from constrained pipes and oversupply. That’s certainly how it all started. Regardless of how things have evolved, another way to look at the market is from the other side of the till: Canadian oil and gas producers are undercutting the market and taking share with the cheapest oil and gas in the world.

Canadian oil exports to U.S. refineries have grown to record volumes, at a record pace, coincident with discounted oil prices that started around 2010. Any Wal-Mart executive will tell you that if you cut the price of a product, customers will buy more. As well, those buyers will shun higher price vendors of the same product. Why would an American refinery pay full global price for oil when it can get the same goods about 5 to 10 per cent cheaper from big-box Canada?This is why Canadian producers have taken market share away from other global suppliers such as Mexico, Venezuela, Nigeria and others. And it’s also why Canada has grown to be the world’s fifth-largest producer of oil by volume, selling more oil to the U.S. than ever before.

To some it’s unsettling to think of Canada as the Wal-Mart of the world’s oil and gas industry. But let’s not prejudice the big-box model. Plenty of these mega-enterprises do extremely well. Their price-and-cost-cutting business strategies are aggressive and legitimate in a highly competitive world; their efficiencies second to none.

In fact, many companies in Canada’s oil and gas industry have been adapting to suit the big-box model. Unprecedented process innovation in the field is driving scale and cost reduction. Information technology, logistics and streamlined midstream processes are taking the cost fat out of supply lines. New modes of transport like oil-by-rail and barge are creating many new sales relationships with refineries that were never customers before. On all these fronts, leading Canadian companies have been advancing to expand their businesses under discounted prices.

An unsettling aspect of muscular big-box stores is that they put the “little guy” out of business in the domestic market. That’s generally true. Gone are the days when the corner bookstore can make a buck in the shadow of Amazon. Such Darwinism is alive in the Canadian oil patch too. The mom n’ pop oil company can ill compete with a skinny balance sheet, a high cost structure and a patchwork quilt of un-scalable land.

Yet there are high-value roles for smaller independents in the fray. Producers with superior geology, access to capital, cost control discipline, and the ability to innovate will continue to command a market share. The challenge and opportunity for smaller companies is to adapt their business plans to co-exist in the competitive fray. Innovators and niche players in the Canadian oil patch are already playing a strong role as the developers of new, high-quality, scalable plays to feed the big-box machine.

Canada’s oil and gas industry will continue to strengthen its business processes, just as big-box stores do, until such time that North American oil and gas prices equalize with the rest of the world. When that happens it will be time to adopt a new, premium-pricing model. Starbucks anyone?

Peter Tertzakian is chief energy economist at ARC Financial Corp. in Calgary and the author of two best-selling books, A Thousand Barrels a Second and The End of Energy Obesity.

Suncor ships first western crude to Europe

24 Sep 2014
Calgary Herald
DAN HEALING
CALGARY HERALD DHEALING@CALGARYHERALD.COM
Suncor ships first western crude to Europe
Oilsands giant Suncor Energy Inc. is sending its first ocean tanker loaded with western Canadian heavy crude to Europe, a company spokeswoman confirmed Tuesday.
Sneh Seetal said the shipment is being made from the port of SorelTracy on the St. Lawrence River in Quebec, but would not say who the buyer is, where or when the ship is going in Europe, how much oil is involved, whether the heavy oil originates in the oilsands or even whether it has all been produced from Suncor operations.
“This is the first shipment of western Canadian crude that we would have sent by rail to the Kildair terminal in Sorel-Tracy, Quebec, where it will be loaded on ships,” she said.
“But to be clear, our East Coast production has been exported for a long time, largely dependent on supply and demand and market conditions.”
She said the shipment is being made as part of Suncor’s marketing strategy to find new customers and is not necessarily going to be an ongoing operation.
“Canada and the U.S. would remain our key markets, but it is important that we establish alternate customers outside North America,” Seetal said.
Pipeline bottlenecks linked to the delay of the Keystone XL project have choked access of western Canadian oil to the U.S. market, leading to lower prices and rapid growth in crude-by-rail transportation.
Phil Skolnick, an oilsands analyst for Canaccord Genuity, said shipments to new markets including India and Indonesia are becoming more common as producers in Western Canada anticipate gaining tidewater access either by new pipeline construction or through rail-loading terminals.
“What’s unique about this is it’s the first time you’ve had western Canadian heavy crude shipped off the East Coast,” he said. “There has been some from the West Coast.”
The tanker is being loaded with 600,000 barrels of Western Canada Select crude, according to a Bloomberg report, which would be used to test refinery compatibility and markets in Europe.
Last spring, a cargo of western Canadian heavy oil was reportedly shipped by Spanish energy firm Repsol through an American port for testing in Spain.
The economics of transporting oil by rail to the East Coast and by tanker to Europe come down to the price difference between New York standard West Texas Intermediate and London-traded Brent, Skolnick said.
A large difference in the price per barrel would be needed to cover higher transportation costs and get full benefit of world prices for the oil.
Suncor has been shipping crude by rail to its 137,000-barrel-per-day Montreal refinery to displace more expensive sources and has said rail will be an important part of future marketing.

Why oil prices are dropping despite Mideast unrest

Why oil prices are dropping despite Mideast unrest
Jeff Rubin
Special to The Globe and Mail
Published Monday, Sep. 22 2014, 7:49 AM EDT
Last updated Monday, Sep. 22 2014, 7:52 AM EDT
Canada’s oil patch is basking in an extended sweet spot of sorts. Commodity prices aren’t spiking in a way that’s sure to sink the global economy, nor are they plumbing depths that would force small producers out of business and big players to start tightening their belts and cutting jobs. The global oil market, however, is changing and nowhere are the signs more evident than the reaction to what’s happening in the Middle East.
In the past, military conflicts in the Middle East and the attendant threat of supply disruptions would send oil prices soaring. Today, oil prices are falling even as the region is seemingly unraveling. Civil wars are unfolding in Iraq, Syria, and Libya, atrocities by ISIS have the western world mounting military action, and Hamas and Israel are coming off arguably the most intense period of conflict in years. The region feels like a tinderbox. Oil supply has already suffered in Libya and Iraq and the threat of production losses is looming over other countries in the region.
Historically, such widespread unrest would have caused global oil prices to march higher, but instead of rising against the backdrop of heightened geopolitical risks, Brent, the global price benchmark, has recently sunk below $100 a barrel. Despite the unrest in the world’s most important oil producing region, the price of Brent is now actually 16 percent lower than it was in June.
On one hand, the world’s major oil consuming economies can let out a big sigh of relief. In the past, oil shocks emanating from the Middle East have led to devastating recessions. For investors in oil companies, though, the recent retreat in global crude prices raises a different question. If crude can’t rally on what’s happening in the Middle East, then what will it take to move prices higher? Does today’s disconnect between global oil markets and the chaos that’s gripping the region signal an end to the era of triple digit oil prices? If so, what are the consequences for North America’s oil industry?
According to U.S. shale producers, it’s the prolific production from the Bakken and the Eagle Ford that’s taken the edge away from OPEC’s market clout. Thanks to the contribution from unconventional plays, U.S. oil production is threatening to surpass the output from Russia and even Saudi Arabia. Although current U.S. law prohibits raw crude from being sold abroad, the sale of 3.5 million barrels a day of refined products such as gasoline and diesel is, ostensibly, helping to keep a cap on the price of oil elsewhere in the world.
It’s a cute theory, but the real reason global oil prices are falling doesn’t have much to do with a bump in the amount of refined products that are being exported from the U.S. In actuality, it’s the same reason that coal prices have been cut in half over the last two years — demand is no longer increasing at the rate it once was.
U.S. oil consumption, by far the largest in the world, has recently fallen to 18.6 million barrels a day, down from nearly 21 million prior to the last recession. European oil demand peaked more than 20 years ago and has fallen in each of the last five years. Even China’s thirst for oil is diminishing as economic growth there shifts into a lower gear. The country’s latest industrial production numbers were the weakest since 2008. Indeed, global oil demand forecasts are being cut by nearly everyone in the business, whether it’s the International Energy Agency, the U.S. Energy Information Agency or even OPEC.
If the trend towards weakening demand growth continues, there’s only one direction for oil prices to go. It’s the same direction that coal prices have already went. Newcastle spot prices, essentially the global benchmark price for coal, have fallen from a peak of more than $140 a ton in early 2011 to less than $70 a ton.
Tumbling prices have wreaked havoc in the industry. Coal companies have gone bankrupt, mines have closed and investors have seen their portfolios decimated. Since early 2011, coal giants such as Peabody Energy and Arch Coal have shed more than 80 per cent of their market value. If crude prices end up mimicking their fossil fuel cousin, prices could be heading as low as $40 to $60 a barrel in the not-too-distant future.
For the moment, it might seem like North America’s unconventional production has relegated OPEC to the sidelines. That can easily happen in a world of $100 oil, because such high prices offer enough incentive for producers to bring on new supplies from expensive sources such as the Bakken or Alberta’s oil sands. In a world of falling prices, however, it will be high cost production from shale formations and the oil sands, not the low cost conventional crude from places such as Saudi Arabia and Iran that will be hit the hardest. Investors in North America’s oil sector need to ask themselves what happens when lower prices make those plays uneconomic.

Landmark Fracking Study Finds No Water Pollution

Landmark Fracking Study Finds No Water Pollution

by  The Associated Press

Kevin Begos

Tuesday, September 16, 2014

 

PITTSBURGH (AP) — The final report from a landmark federal study on hydraulic fracturing, or fracking, found no evidence that chemicals or brine water from the gas drilling process moved upward to contaminate drinking water at a site in western Pennsylvania.

The Department of Energy report, released Monday, was the first time an energy company allowed independent monitoring of a drilling site during the fracking process and for 18 months afterward. After those months of monitoring, researchers found that the chemical-laced fluids used to free gas stayed about 5,000 feet below drinking water supplies.

Scientists used tracer fluids, seismic monitoring and other tests to look for problems, and created the most detailed public report to date about how fracking affects adjacent rock structures.

The fracking process uses millions of gallons of high-pressure water mixed with sand and chemicals to break apart rocks rich in oil and gas. That has led to a national boom in production, but also to concerns about possible groundwater contamination.

But the Energy Department report is far from the last word on the subject. The department monitored six wells at one site, but oil or gas drilling at other locations around the nation could show different results because of variations in geology or drilling practices. Environmentalists and regulators have also documented cases in which surface spills of chemicals or wastewater damaged drinking water supplies.

“There are a whole wealth of harms associated with shale gas development” separate from fracking, said Maya K. van Rossum, of the Delaware Riverkeeper group. She mentioned methane gas leaks, wasteful use of fresh water and air pollution, and said the Energy Department study confirms a point that the Riverkeeper has been making: that faulty well construction is the root cause of most problems, not fracking chemicals migrating up through rocks.

A separate study published this week by different researchers examined drilling sites in Pennsylvania and Texas using other methods. It found that faulty well construction caused pollution, but not fracking itself.

Avner Vengosh, a Duke University scientist involved with that study, just published in The Proceedings of the National Academy of Sciences, said in an email that it appears the Energy Department report on the Pennsylvania site is consistent with their findings.

The leading industry group in Pennsylvania said the Energy Department study reaffirms that hydraulic fracturing “is a safe and well-regulated technology.” Marcellus Shale Coalition president Dave Spigelmyer said in an email that the study reflects “the industry’s long and clear record of continuously working to enhance regulations and best practices aimed at protecting our environment.”

The Energy Department report did yield some surprises. It found that the fractures created to free oil or gas can extend as far as 1,900 feet from the base of the well. That’s much farther than the usual estimates of a few hundred feet. The Energy Department researchers believe that the long fractures may have followed existing fault lines in the Marcellus Shale or other formations above it.

The department study also ran into problems with the manmade markers meant to track possible long-term pollution. The Energy Department said it was able to track the markers for two months after fracking, but then that method had to be abandoned when it stopped working properly.

Copyright 2014 Associated Press. All rights reserved. This material may not be published, broadcast, rewritten, or redistributed.

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Citing sanctions, Exxon says it will wind down exploratory Russian drilling

Citing sanctions, Exxon says it will wind down exploratory Russian drilling
Jonathan Fahey
NEW YORK — The Associated Press
Published Friday, Sep. 19 2014, 2:16 PM EDT
Last updated Friday, Sep. 19 2014, 2:27 PM EDT
Exxon Mobil Corp. said Friday that it will wind down a drilling project in Russia in compliance with U.S. sanctions, but said it received a license to keep working beyond the sanctions’ deadline in order to complete the work.
U.S. sanctions against Russia over its involvement in the Ukraine require the removal of U.S. workers on projects in the Russian Arctic and other select locations by Sept. 26.
Exxon is drilling an exploratory well in the Kara Sea in the Russian Arctic, and had planned to stop drilling in October in order to remove equipment and personnel before winter set in.
Exxon said it has received a licence from the U.S. Treasury Department for more time to wind down operations safely and close up the project before winter “to ensure a safe and environmentally responsible completion,” said Exxon spokesman Richard Keil. “The license is non-renewable and no further work is permitted.”
Unless the sanctions remain in place for many more months, they are not expected to lead to a delay in the Kara Sea exploration project.
The project is part of a broad collaboration between Exxon and the Kremlin-controlled Rosneft, Russia’s largest oil company. The two aim to explore for oil and gas in technically challenging formations in Russia.
These formations are thought to hold large troves of hydrocarbons, but producing oil from them requires the type of expertise found at western oil companies such as Exxon.
Even if successful, the projects aren’t expected to result in new oil and gas production for several years. But they represent an important and possibly enormous resource that could help both Exxon and Russia keep oil production high as current fields naturally deplete.

Keystone XL cost may surge 85% to $10-billion, TransCanada says #kxl

Keystone XL cost may surge to $10-billion, TransCanada says
Rebecca Penty and Yuriy Humber
Bloomberg News
Published Friday, Sep. 19 2014, 6:15 AM EDT
Last updated Friday, Sep. 19 2014, 7:17 AM EDT
The cost of building the Keystone XL oil pipeline, which is awaiting approval from the U.S. after an initial rejection, may climb 85 per cent to $10-billion (U.S.), according to developer TransCanada Corp.
The new estimate, confirmed by Calgary-based company spokesman Shawn Howard yesterday after comments made by chief executive officer Russ Girling to the Wall Street Journal, increases the project cost from the current $5.4-billion.
TransCanada, the second-largest Canadian pipeline operator, applied six years ago to build Keystone XL to carry rising supplies of oil-sands crude to U.S. Gulf Coast refineries. The pipeline was rejected by President Barack Obama in 2012. TransCanada then split up the project to build the southern portion first and refiled for approval for the northern leg with an alternate route in Nebraska.
The U.S. State Department is awaiting the outcome of a Nebraska court battle over the regulatory review of the line’s path through the state before making a ruling. The department has jurisdiction over the project because it would cross the U.S. border with Canada.
Environmental campaigners have stalled progress on the project, arguing it would boost carbon dioxide emissions and hurt the communities that live in its proposed path. The project is one of several that activists are due to highlight at demonstrations planned at the United Nations Climate Summit, which starts next week.
TransCanada CEO Girling this week called the opposition ignorant of the project’s realities. The lack of a decision on whether the project will go ahead has resulted in it carrying costs of $150-million a year, Girling said.
Carbon Emissions
A final environmental review of the project, released by the State Department in January, found that it would increase emissions by 1.3 million tons to 27.4 million tons of carbon dioxide each year. That’s less than 0.5 per cent of total U.S. greenhouse gas emissions in 2012.
The U.S. House of Representatives voted yesterday 226-191 to approve a broad package of energy measures that would give the green light to the Keystone XL project. Among the measures are processes to speed up lease sales and energy permit issuances.
Enbridge Inc. is Canada’s largest pipeline company, by market value.
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