• 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.
- WTI oil prices are forecast to average US$94.25 per barrel in 2014-15
- Exchange rate of 91.50
- 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)
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.
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.
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.
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.
49 North Resources Inc., Tom MacNeill, President and Chief Executive Officer, 306-653-2692 or firstname.lastname@example.org
Canadian oil producers thriving with their big-box business model
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.
Landmark Fracking Study Finds No Water Pollution
by The Associated Press
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.
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