Canadian natural Buys assets, shell

sells

Crude prices consolidated its hold over $100 during the past week on expectations of an improving demand outlook and smaller-than-expected rise in inventories, while natural gas topped $6 for the first time in 5 years as the latest bout of frigid temperatures fuel further concerns about the already tight supplies.Among the newsmakers, Canadian Natural Resources Ltd. (CNQ) entered into a $3 billion deal to buy some of Devon Energy Corp.’s (DVN) Canadian gas assets, while Royal Dutch Shell plc (RDS.A) will be selling its Australian refinery and petrol stations for about $2.6 billion. Crude Oil:Crude prices edged up a little last week on positive demand outlook for heating oil amid below-normal temperatures that have prevailed for most part of the winter. The commodity got some more support from news of ongoing conflicts in Libya and South Sudan that could pressure the black gold’s supply. Sentiments were

further brightened by the Energy Information Administration (EIA) report that showed a lower-than-expected increase in oil inventories.To some extent, the bulls were offset by a surprise drop in industrial production and dismal existing home sales data that seems to question

the country’s economic recovery. A contraction in Chinese manufacturing also weighed on crude prices.As a result of these factors, by close of trade on Friday, West Texas Intermediate (WTI) oil was in the black and settled at just over $102.00 per barrel, gaining 2.0% for the week.

Natural Gas:Natural gas rallied last week to its highest level in 5 years on the back of a large decrease in supplies and forecasts of continued freezing cold weather conditions.The EIA’s weekly inventory release showed that natural gas stockpiles

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held in underground storage in the lower 48 states fell by 250 billion cubic feet (Bcf) for the week ended Feb 14, within the guided range (of 248–252 Bcf drawdown). Importantly, the decrease – the fourth successive drop of 230 Bcf or more – was considerably higher than both last year’s withdrawal of 131 Bcf and the 5-year (2009–2013) average reduction of 133 Bcf for the reported week.Chilly weather forecasts – in the northern U.S. over the next few days – are likely to further spur natural gas’ demand for heating.Influenced by these factors, natural gas prices ended Friday at $6.14 per million Btu (MMBtu), up 18.0% over the week.Canadian Natural Buying Devon Assets for $3BIndependent energy explorer

Canadian Natural Resources Ltd. has agreed to acquire certain liquids-rich natural gas properties in western Canada from Oklahoma City-based Devon Energy Corp. for $2.86 billion in cash. The market reacted positively to the news, which was announced before market hours on Wednesday, Feb 19.Shares of Canadian Natural ended at $36.69 on that day – up 2.6% from Tuesday’s close. The to-be-bought assets – adjacent to Canadian Natural’s existing fields in the region – hold an estimated 272.2 million oil-equivalent barrels (MMBOE) in proved reserves (70% gas) and will add 86,633 BOE to the nation’s largest heavy oil outfit’s daily production.Shell to Get $2.6B for Australian AssetsEurope’s largest oil company Royal Dutch Shell plc has entered into an agreement with Swiss international

energy trading giant Vitol Group to sell its Australian downstream assets for approximately $2.6 billion. The transaction – subject to regulatory approvals – is expected to close in 2014.The to-be-sold properties covers the Anglo-Dutch energy major’s Geelong refinery near Melbourne and its 870 retail outlets, apart from bulk fuels, bitumen, chemicals and a portion of Shell’s lubricants businesses in Australia. However, the scope of the contract does not include the Aviation unit, which will remain with The Hague, Netherlands-based group.Exxon Full Reserve Replacement ContinuesEnergy giant Exxon Mobil Corp. (XOM) announced that it has replaced 103% of its 2013 production by adding proved oil and gas reserves totaling 1.6 billion oil-

equivalent barrels, including a 153% replacement ratio for crude oil and other liquids. However, this did not have any impact on the bourses as the integrated oil major has been replacing more than 100% of its reserves regularly over the past two decades. At year-end 2013, Exxon Mobil’s proved reserves totaled 25.2 billion oil-equivalent barrels, comprising 53% liquids, up from 51% in 2012, and 47% natural gas, down from 49% in 2012.Cabot Falls Despite Strong Q4Natural gas producer Cabot Oil & Gas Corp. (COG) slid 8% despite reporting fourth quarter numbers that beat analyst expectations on the back of significant increase in production levels. Much of the share price decline seems to be tied to Cabot’s failure to match its earlier blowout quarters. As mentioned above, though the company

actually beat estimates, it was not enough to appease investors, who expected more growth.Nabors Surges on Q4 BeatShares of onshore contract driller Nabors Industries Ltd. (NBR) popped more than 13% on Wednesday following a better than expected earnings announcement. The Hamilton, Bermuda-based company’s outperformance was primarily due to impressive gains from international operations. In more encouraging news for the investors, Nabors said that domestic drilling fundamentals have improved considerably, with pricing and utilization expected to be strong during the near future.

Companies say B.C.’s lnG tax too hiGh

One of the first questions British Columbia’s Finance Minister Mike de

Jong was asked when he introduced the Liberal government’s proposed Liquefied Natural Gas Income Tax as part of last week’s budget, was how oil and gas companies would react to paying a tax that could top out at seven per cent.“Of course, they want zero,” he replied.But de Jong pointed to a recent government-commissioned Ernst and Young survey that concluded B.C.’s all-in taxes — corporate, federal, provincial, municipal, carbon and the new LNG tax — put the province near or at the top of the heap compared to the tax regimes of potential competitors in Australia and the United States.The B.C. plan “appears competitive relative to the existing frameworks in Australia and the five U.S. states,” stated the 12-page review, with the proviso that their analysis does not

take into account any “discretionary credits that a proponent may or may not be able to obtain.”The provincial budget last week revealed the government’s proposed two-tiered LNG tax, which will be introduced as legislation in the fall. The first tier will be 1.5 per cent to be introduced at the start of production. The second tier, when introduced, could rise to seven per cent once the plant is running and capital costs have been deducted.But no LNG revenues are in the government’s three-year fiscal plan and the B.C. finance minister acknowledged tax dollars won’t flow until plants are in production, which would be in 2018 at the earliest.The Canadian Association of Petroleum Producers, which represents major oil and gas companies, was lukewarm towards

the proposed tax regime. B.C. spokesman Geoff Morrison said the plan provides a framework but more work needs to be done on the rates.A spokesman for LNG Canada, a proposed export facility near Kitimat that includes Shell Canada ( TSX:SHC), Korea Gas, Mitsubishi and PetroChina, said the company supports an LNG tax, but the seven per cent rate may be too high.“We appreciate the government’s commitment to flexibility on the two-tiered piece, ” said Shell Canada spokesman David Williams. “It’s clear that the rate has to be globally competitive. We’re concerned that the top end of that range in the second tier will not achieve that level of global competitiveness.”Greg Kist, president of TransCanada Corp.’s (TSX:TRP) Pacific Northwest LNG, said his company,

which has proposed a multibillion-dollar LNG facility near Prince Rupert, is looking for clarity from the government on the tax regime before making a final investment decision by the end of the year.“For us, at this point in time, it’s a situation where we want to understand the details,” he said. “The LNG tax in and of itself is merely one piece of the fiscal framework we need to get clarity on before we can make a final investment decision.”Pacific Northwest LNG includes Malaysia’s Petronas, Japex and Petroleum Brunei.The Ernst and Young analysis included an aggregate review of expected taxes and royalties from LNG plants in Australia and B.C. over 20 years of operations.It found Australia has a slight edge on the low-end of returns, collecting about $151 billion in taxes and

royalties, compared to $152 billion in B.C. But at the high-end after 20 years, B.C. wins out across all jurisdictions, charging about $270 billion in taxes, compared to $320 billion in Australia. Texas had the highest aggregate taxes after 20 years, coming in at about $370 billion.The Liberals believe LNG is a trillion-dollar opportunity that could pay off the provincial debt, currently at almost $62 billion.But industry analysts and the Opposition New Democrats say the Liberals are already a year behind schedule for a tax and royalty structure and in danger of losing the race.B.C. Natural Gas Development Minister Rich Coleman said more than nine months of work have gone into developing the tax regime and he’s convinced it will keep B.C. competitive.Coleman said B.C. offers a 100-

year supply of natural gas, a shorter distance to Asian markets and a cooler climate to extract and cool the gas to liquid form, which occurs at minus 160 Celsius.“I heard one company president say at a conference, the ambient temperature of British Columbia is equivalent to getting the pipeline for free because you use less energy to cool it down,” he said.Coleman said tax negotiations with the oil and gas companies are at the stage where “somebody’s going to blink.”

tundra planninG nitroGen/Water

eor pilot in Bakken/three Forks

Tundra Oil and Gas Partnership is seeking regulatory approval for an immiscible nitrogen flood in the Middle Bakken/Three Forks tight

oil formations in the Daly Sinclair field of southwest Manitoba.Based in Winnipeg, Tundra is a privately held light oil producer that operated the drilling of 168 wells in Canada last year -- 163 in Manitoba and five in Saskatchewan.This isn’t the company’s first foray into gas flooding in a tight oil formation. Since August 2008 Tundra has been operating a miscible gas pilot injecting carbon dioxide in the southeast quarter of section 04-08-28W1 within Sinclair Unit No. 1. Last August this pilot was approved for conversion to a water-alternating-gas project.Now the company is applying for an immiscible gas injection pilot using nitrogen. (In miscible gas floods, the injected gas forms a single homogeneous phase with the oil. The resulting fluid has lower viscosity, reduced interfacial tension and

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improved mobility. While immiscible gas doesn’t form a single phase with the oil, it still has the benefit of improved pressure maintenance and sweep efficiency within the reservoir.)The pilot would use two horizontal injection wells. Based on expected reservoir permeability and pressure, Tundra is forecasting an average water injection rate of 10 to 25 cubic metres a day. The nitrogen injection rate is expected to be 2,000 to 5,000 cubic metres a day.Tundra expects to alternate between nitrogen and water injection every

three to six months to optimize the flood front and minimize gas channelling and breakthroughs.In its application to the Manitoba government for the immiscible gas injection pilot, Tundra is seeking approval to install nitrogen injection equipment at two horizontal injectors in section 34-08-28W1.“While the theoretical benefits of miscible EOR [enhanced oil recovery] are greater than for immiscible EOR, the operating costs are also greater,” Tundra says in its application, noting the current cost of CO2 renders

commercial expansion uneconomic.The company said it plans to use nitrogen because it is “readily available in the atmosphere.” Even with the initial setup expense of the nitrogen generator, a nitrogen flood would cost less per barrel to operate than a CO2 project, the company said.“N2 has the additional benefit of not being a greenhouse gas and is environmentally safe and will not need additional facilities to recapture the produced gases,” Tundra said.Due to the nature of its reservoir,

the company believes gas can provide greater pressure support than water due to gas’s favourable mobility ratio to oil.Nitrogen would be generated on site because transporting liquid nitrogen is much more difficult than transporting CO2 due to nitrogen’s low boiling point, Tundra said. It would use a system that filters nitrogen from the atmosphere, then compresses and stores it.“This is a significantly more cost effective method of delivering gas injection [than] Tundra’s existing

CO2 pilot,” the company said. CO2-based EOR pilots in Western Canada typically use trucked CO2.Injection water for the pilot would come from the Lodgepole formation, which supplies the existing Sinclair units. Produced water isn’t currently used for any water injection in the Tundra-operated Sinclair units and the company said it has no plans to use produced water for the proposed pilot.To do the EOR project, Tundra has applied to unitize 16 legal subdivisions in Section 34 of Township 8, Range

28 W1. The proposed unit -- which would be called Ewart Unit No. 5 -- would consist of 16 tracts based on 40-acre legal subdivisions.Tundra holds 100 per cent working interest ownership of the lands it is applying to unitize. The proposed unit would include four existing producing wells in the Middle Bakken/Three Forks reservoir. Total net original oil in place in the proposed project area is estimated at 2.78 million bbls for an average of 174,000 bbls per 40-acre legal subdivision.

According to Tundra’s application, oil production per well in the proposed project area peaked in 2009 at 268 bbls a day. As of last November, average oil production per well had fallen to 9.6 bbls a day. Production is forecast to continue declining at a rate of nearly 29 per cent a year. By last Nov. 30 cumulative production from the four wells within the proposed Ewart Unit No. 5 project area was 206,500 bbls of oil and 292,800 bbls of water. The recovery factor was 7.4 per cent of the net original oil in place.

Estimated ultimate recovery of primary proved producing oil reserves in the proposed project area is estimated at 256,000 bbls with 49,500 bbls remaining as of last Nov. 30.Under the current primary production method, ultimate oil recovery of the proposed Ewart Unit No. 5 is forecast to be 9.2 per cent of the original oil in place.Based on a study by Coho Consulting Ltd., Tundra said the section was deemed to be suitable for a nitrogen flood.

Tundra estimates ultimate recovery of proved oil reserves in the project area, using a secondary water-alternating-gas EOR scheme, would be 379,000 bbls of oil with 176,000 bbls remaining.The company estimates an additional 123,000 bbls of proved oil reserves could be recovered via its proposed unitization and secondary EOR scheme versus the existing primary production method.Tundra estimates water-alternating-gas injection in the proposed Ewart Unit No. 5 would boost the total recovery factor to 13.5 per cent.

Under the planned EOR scheme the existing horizontal 08-34-08-28 producer well would be converted to an injector and a new injection well would be drilled between existing horizontal producers.Tundra’s water-alternating-gas injection pilot would test two different production patterns within the same section. One pattern would test 40-acre spacing, the other 20-acre spacing. The 40-acre spacing pattern would be achieved by converting the existing 08-34-08-28 producer into an injector. This injector would

support the production from 00/01-34-08-28 and 00/09-34-08-28.To create the 20-acre pattern, a new open-hole horizontal injector would be drilled between 09-34-08-28 and 16-34-08-34.Pending regulatory approval, Tundra said the pilot could begin operating next summer.The company plans to evaluate over five years whether water-alternating-nitrogen injection will improve oil recovery where waterflooding and miscible gas flooding have been deemed uneconomic due to poor reservoir quality.

transCanada pipeline saFety

praCtiCes need to improve, Finds neB

audit

Calgary-based company breaking the rules in some areas, says National Energy BoardA National Energy Board audit has found room for improvement when it comes to TransCanada’s pipeline safety practices.Although the federal energy watchdog is “of the view that the processes

presently used by TransCanada have identified the majority, and most significant, of its hazards and risks,” it says the company is still breaking the rules in some areas.The NEB had scheduled an audit on TransCanada’s integrity management programs to begin last spring, but decided to move on it sooner after a then-employee of TransCanada came forward with allegations of safety lapses.The audit took place between November 2012 and August 2013.“The audit has confirmed that, in response to these allegations, TransCanada has developed and implemented a program of actions with the goal of correcting and preventing similar occurrences,” the NEB said.“The board notes that a number of the allegations of regulatory non-compliance were identified and addressed by TransCanada only after the complainant’s allegations were made and were not proactively identified by the company’s management system.”According to the report released by

the NEB on Monday, the audit found the Calgary-based pipeline operator was meeting all legal requirements in five of nine aspects of the review.But there are four other areas in which the company was found to be non-compliant:• Hazard identification,risk assessment and control.• Operationalcontrolinupsetor abnormal operating condition.• I n s p e c t i o n ,measurement and monitoring.• Management review.In a news release, the NEB said a finding of non-compliance does not necessarily mean there’s an immediate safety hazard.TransCanada must file a corrective action plan to the NEB within 30 days detailing how it intends to fix the problems.Company taking action, says spokespersonTransCanada spokesman Shawn Howard said the company has taken action on a number of fronts.For instance, it’s improving

inspections on its NGTL natural gas system in Western Canada and its monitoring of commodities carrying dangerous hydrogen sulphide gas. It has also appointed an executive to oversee its management systems and meeting of regulatory obligations.“The findings from this review will be included in a program of improvements, many of which we have already underway, that we are committed to as part of our ongoing efforts to ensure our pipeline safety management system is as effective as it can be,” Howard said.The report comes as TransCanada awaits a U.S. decision on its

controversial Keystone XL pipeline, which would connect 830,000 barrels per day of mostly oilsands crude to U.S. Gulf Coast refineries.The $5.4-billion project would expand an existing system that started delivering crude to the U.S. Midwest in 2010.In its report, the NEB said it’s looking into certain steel pipe and fittings on the existing Keystone system “with the potential to exhibit lower than specified yield strength.”“This investigation remains ongoing. Resolution of the investigation and any required remedial actions will be determined outside the audit.”