CanElson's Growth Plans Continue To Take Shape

CanElson's Growth Plans Continue To Take Shape After continued growth and strong second quarter results, CanElson Drilling Inc. announced this morning that its common shares will begin trading on the Toronto Stock Exchange (TSX) at the opening on Sept. 13, 2011. As a result, the company’s shares will be delisted from the TSX Venture Exchange at the same time. CanElson said its common shares will continue to trade under the trading symbol “CDI.” Currently, the company has 73.14 million common shares issued and outstanding. “Listing on the TSX was a logical next step given the rapid growth of CanElson from one rig in December 2008 to 33 rigs [36 by January 2012] today. We envision that the TSX listing will increase the liquidity of the company’s common shares and provide greater access to capital,” president and chief executive officer Randy Hawkings said in a statement. As of Sept. 12, CanElson was operating 33 rigs: 19 drilling rigs in the Western Canadian Sedimentary Basin, six (five net) drilling rigs in Texas, four drilling rigs in North Dakota, as well as two (one net) drilling rigs and two (one net) service rigs in the Misantla-Tampico Basin of Mexico. Of note, the company’s owned drilling rig fleet has an average age of less than five years, an average total vertical depth rating of 3,700 metres, and all rigs are capable of drilling horizontal and resource play wells. In an operational update, the company said that as of Sept. 12, 100 per cent of its Canadian rig fleet is drilling and during the first two months of the third quarter CanElson’s Canadian rig fleet has operated at 77 per cent utilization. The company said its expectation for the remainder of the third quarter is full operating activity with all of the rigs contracted. As well, CanElson said 90 per cent of its United States rig fleet is drilling and during the first two months of the third quarter the rig fleet operated at 75 per cent utilization, which was negatively impacted by wet weather conditions in North Dakota. All of the rigs in the U.S. are contracted and full operating activity is expected in west Texas as well as North Dakota for the remainder of the third quarter, subject to moving truck availability. Given the present market demand for CanElson’s style of resource-based drilling rigs, the company expects to continue to have strong activity levels for the remainder of 2011 and into 2012. In June, as part of the 2011 drilling rig construction program, the first of five purpose-built small footprint ultra-heavy-duty telescoping double drilling rigs (tele-double) was deployed to west Texas. The second rig was deployed to northern Alberta at the end of August. The third rig is expected to be deployed to the field by the end of September to northern Alberta. “We expect the remaining two rigs from the 2011 rig construction program to be deployed as originally anticipated by November 2011 and January 2012, respectively,” the company said. Meanwhile, during the second quarter the company’s revenues increased 127 per cent to $25.14 million from $11.1 million during the same period last year. Earnings improved to $3.33 million from a net loss of $630,000 a year earlier, while cash flow was up more than 1,900 per cent to $6.05 million from $300,000 for the three months ended June, 30, 2010. Quarterly results benefited from the growth in CanElson’s drilling rig fleet to 26.5 (24.5 net) average rigs available for operation compared to an average of 8.1 (7.1 net) drilling rigs the prior year, and a revenue rate increase to an average of $28,400 per rig operating day compared to $26,500 per rig operating day in 2010. As well, the company said it achieved strong financial results during the seasonally weak second quarter as foreign operations in the U.S. and Mexico made significant contributions to revenue, while much of the domestic rig operations were curtailed due to exceptionally wet spring conditions, including flood conditions in southeast Saskatchewan. Financial results for the six months ended June 30, 2011, were also strongly improved year-over-year (see tables). During the second quarter the company continued to focus its growth on rigs capable of drilling horizontal and resource play wells with the acquisition of 100 per cent of the outstanding units of Redhawk Drilling, LLC for approximately $19 million. Redhawk operated four drilling rigs in North Dakota, which were primarily drilling horizontal wells. That aligns with the company’s focus on rigs capable of drilling resource play wells and adds operations in a region that is pursuing oil-based drilling activity. “We continued to focus our growth on oil and liquids weighted resource plays with the acquisition of Redhawk in June,” Hawkings said. “The addition of Redhawk combined with our west Texas operations provides exposure to approximately 56 per cent of the U.S. oil-directed drilling market.” CanElson Drilling Inc. Financial Summary (Million $) Profit Profit Per Share Cash Flow Cash Flow Per Share Revenue Capital Expenditures Three Months Ended June 30 2011 (Note 1) $3.33 $0.05 $6.05 $0.08 $25.14 $31.29 2010 (Note 1) ($0.63) ($0.02) $0.30 $0.01 $11.10 $10.17 Six Months Ended June 30 2011 (Note 1) $10.07 $0.15 $18.86 $0.29 $66.09 $108.57 2010 (Note 1) ($0.32) ($0.01) $1.77 $0.06 $22.71 $17.25 Three Months Ended June 30 2010 (Note 2) $0.01 $0.75 $0.03 $11.10 $10.81 2009 (Note 2) ($0.56) ($0.02) ($0.48) ($0.02) $0.28 Six Months Ended June 30 2010 (Note 2) $0.32 $0.01 $2.14 $0.08 $22.71 $17.89 2009 (Note 2) $0.13 $0.99 $0.04 $2.98 $5.52 Note 1 = IFRS accounting Note 2 = GAAP accounting

Commodity Corner: Oil Loses on Volatile Equities, Stronger Dollar

Commodity Corner: Oil Loses on Volatile Equities, Stronger Dollar by Matthew V. Veazey | Rigzone Staff | Friday, September 16, 2011 Light sweet crude oil on Friday lost $1.44 to settle at $87.96 a barrel. The WTI traded within a range from $87.00 to $89.78. Volatile equities markets, a stronger dollar, and lingering doubts about a resolution to the euro-zone debt crisis dampened the demand outlook for oil during Friday's session. The Dow Jones Industrial Average, S&P 500, and Nasdaq spent some time below the breakeven point Friday morning before posting modest gains by the closing bell. The euro, meanwhile, lost 0.68 percent against the dollar. When the greenback strengthens against other major currencies, it becomes a less attractive value for some investors. The November Brent contract price ended the day at $112.22 a barrel. It fluctuated from $111.61 to $114.10. Thursday's release of a bearish report on inventories by the Energy Information Administration, coupled with predictions of warmer weather in the Midwest and East Coast, sent natural gas into negative territory. The October contract price fell seven cents to settle at $3.81 per thousand cubic feet. Front-month natural gas peaked at $3.895 and bottomed out at $3.79 Friday. Reformulated gasoline remained flat at $2.78 a gallon—also the intraday low. The October contract price topped off at $2.84 during the final session of the week.

The oil sands enters an era of opportunity and uncertainty

Advocates and opponents of Alberta's resource jewel are watching the sector closely
By Darren Campbell






September 1, 2011






Alberta’s oil sands have never been more popular – or more controversial. In a world run by hydrocarbons, the province’s 170 billion barrels of oil sands reserves is one of the most tantalizing sources of fuel on Earth. Oil companies big and small are jockeying for position to extract it, energy-hungry nations are looking to import it, and the resource owners – Albertans – are looking to maximize the return they can get from it.

But such an important resource tends to grab the attention of more than just those that want to exploit it, and the substantial environmental and social impacts that comes with oil sands development has resulted in a heightened degree of public scrutiny on the sector. Long gone are the days when the oil sands could operate in obscurity. It’s now a world-class resource, but also an industry in flux, searching for ways to navigate safely through a new era.

The content of our annual oil sands issue reflects this reality. In this issue you will find stories examining how industry, government and the public are coming to grips with the changing nature of the oil sands. In my cover story on Syncrude Canada Ltd. president and CEO Scott Sullivan, I take a look at how this ExxonMobil lifer is bringing the refined petroleum acumen of the biggest of the Big Oil companies to an oil sands pioneer. (We’ve also got an exclusive video providing readers with an inside look at Syncrude’s innovative research center.)

Associate editor Jeff Lewis tackles the thorny issue of two differing visions for value-added oil sands production in Alberta. Alberta Oil assistant editor Steve Macleod writes about the push by a handful of firms to use electrical currents rather than natural gas to create steam and unlock bitumen from its rocky underground prison – an innovation that could lessen the sector’s greenhouse gas emissions if it proves to be viable.

Also included in our September package is Bill Rankin’s piece detailing how the controversies erupting over planned pipeline expansions to ship oil sands production to new markets is presenting the petroleum industry with a new level of risk – one that could stymie its ambitious growth plans for the oil sands. And finally, Carol Christian takes us to Fort McMurray to see how the community’s infrastructure is holding up – and what governments and industry are doing to help it address the shortage – as Fort Mac enters what looks like another boom period.

Canadian success, American failure

Written by Mike Byfieldon March 7, 2011 Although few Canadians really grasp the fact, Canada has achieved enormous success in domestic crude oil production. In contrast, the United States has failed by any measure. Oil & Gas Inquirer’s cover story in January/February describes that success . During the first half of the 20th century, Canada struggled desperately to produce oil from its small proven reserves for two world wars. Simultaneously, the U.S. accounted for 70 per cent of world oil production in 1925, 63 per cent in 1941 and over 50 per cent in 1950. South of the 49th parallel, however, domestic reserves were not replaced despite the fact that American technology dominated the global oil industry. By 1970, the U.S. could no longer supply its own crude consumption. In 2009, Americans imported 63 per cent of their oil. Dependence on foreign energy drains their economy and jeopardizes their national security. Canada could easily have fallen down the same economic crack. Our domestic light and medium crude production peaked in 1973 and has been decreasing ever since. Fortunately, this country developed its heavy and extra-heavy crude resources, as outlined in this issue’s cover story. We’re now better off than ever, and the picture promises to improve further in future. The U.S. did not necessarily have to fall so abysmally short. Its shale oil resource, although technically daunting, has been quantified on an immense scale, easily comparable to Canada’s oilsands and heavy oil. Yet even now, the federal government in Washington continues to downplay shale oil development in Colorado and Wyoming. Ironically, innovative shale oil technology pioneered by Shell Oil in the U.S. may well be deployed more effectively in Alberta’s carbonate bitumen reserves. Canadians do not hear much good about heavy and extra-heavy crude. “Dirty oil,” sneers a tribe of critics across North America—yet they offer no alternative energy sources that would be even faintly reliable. If these perfectionist folks had been on our backs, westerners could not have built transcontinental railways and harnessed the Prairie soil to feed a hungry world. In our own time, two generations of western oilmen have performed on that same magnificent scale.

Riding out the Waves

Aug 2011

Source: Oilweek Magazine


Riding out the waves


Business cycles come and go, but Nexen’s strength and experience prevails to carry it through


by R.P. Stastny



You could say it was the best of times and it was the worst of times. January 2009 was a personal high note for Marvin Romanow as he took over from Charlie Fischer as Nexen Inc.´s new president and chief executive officer. In terms of the business cycle, though, it couldn´t have been a tougher time to take the reigns.

In the first month of Romanow´s tenure, oil prices tanked to below $40 a barrel, financial markets went into hiding, the world economy was grinding to a halt while a host of other challenges for Nexen were still in the oven.

Soon its Long Lake oilsands facility would encounter technical difficulties and balk at reaching its production design capacity target of 72,000 barrels a day. The Macondo oil spill made a mess of the U.S. Gulf of Mexico in the spring of 2010, casting a long shadow over the region´s regulatory process and complicating Nexen´s prospects for its deepwater work with Royal Dutch Shell plc.

And this past spring, the U.K. government increased its supplementary tax on North Sea production to 32 per cent from 20 per cent, a disappointing development particularly for Nexen, which has almost half of its total company production in the North Sea.

In Nigeria, where Nexen has offshore operations, the government is reviewing its royalty regime. In Yemen-a historic engine of growth for Nexen over the last 20 years-negotiations to extend the company´s agreement with the government seem stalled as the Arab popular uprising sweeps through the Middle East.

So as one market analyst put it, "It could be worse for Nexen, but not much."

View from the corner office
Romanow recalls the biggest challenge for him in 2009 was "having the calm to not overreact when commodity prices crashed." Nexen´s experienced board of directors played a crucial role at the time, ensuring the company took a measured and longer-term view of the situation.

To some extent, that long-term focus still prevails today in the midst of challenges Nexen faces and provides the backdrop for Romanow´s leadership.

"In our business, there can be long cycle times to our investments," he says. "For example, we´re bringing on stream with Exxon [Mobil Corporation] and Chevron [Corporation] and Total [E & P Canada] a $10 billion project in West Africa. That was from a discovery that we made in 1998. That was three CEOs ago. So my job is to develop that asset to production and my job will also be to leave a few jobs for the next guy to develop because of the cycle times."

In the context of Nexen´s three-course strategies-conventional oil and gas, shale gas and oilsands-gas production from Nexen´s attractive shale gas prospects in the Horn River Basin may well become the responsibility of Romanow´s successor. So will any subsequent phases of Nexen´s oilsands development at Long Lake because, in the meantime, Romanow has his work cut out for him.

Long Lake
In the oilsands, Nexen arguably gambled on an innovative technology that uses the heavy bottoms of bitumen rather than natural gas to generate steam for its steam-assisted gravity drainage wells and is now paying the price. But taking the longer view, Nexen started working on Long Lake more than a decade ago, and is now part way through ramping up to a production level that will continue for decades to come during which time natural gas prices will wax and wane.

Romanow concedes that in retrospect some of the decisions Nexen made in 2001 would have been made differently today. "We made a very large investment and we should´ve phased it a bit more," he says. "But now, the upgrader we have, the gasifier and the steam is about 80 per cent of the total investment, and those are going to create value. We just need a few more wells. Which take time to drill, but they´re also the cheapest part of the development.

"So here´s the vision," he says. "We didn´t have quite enough wells and we didn´t have the wells located in some of our best resource because we´ve been able to define more resource quality since then. But now we can show investors that we have a game plan and that we can execute on it."

On leadership
Romanaow´s leadership is characterized by collaboration. That doesn´t mean he is any less a captain of industry. It just means he fully taps the resources available to him.

"In a company like ours, it´s not going to be the CEO who sits in his office that creates value," he says. "We have 4,500 employees to create the ideas and to implement those ideas. That´s what leads to world-class performance."

Romanow´s leadership style recognizes that today´s oil and gas industry is more complicated than ever. Whether it calls upon technical expertise to drill beneath 3,000 metres of water, produce gas from tight rock or manage large investments in the oilsands, that complexity requires a lot of talent sets. The CEO, the ultimate generalist, in Romanow´s view, needs to ensure that all the talent sets throughout the organization are engaged and can make their contribution in effectively charting the company´s course.

To this end, Romanow does plenty of listening through formal and informal forums within Nexen, from town halls and weekly or biweekly events called Breakfast with Marv, where eight to 10 Nexen employees from all areas and ranks of the company get a chance to chat about everything from what´s concerning them about their job to what´s going on in their lives.

This level of collaboration also makes the job of getting buy-in almost instantaneous, because those same people actually had a hand in crafting the strategy.

Romanow knows that good ideas come from all ends of the company because he has worked with many people in different roles over the course of his career. He spent time as an engineer in reservoir management and he worked in finance (which eventually earned him a Canada´s CFO of the Year award in 2007 and, in September of the same year, a Petroleum Economist Energy Executive of the Year award).

He has worked with companies that enjoyed enormous success but also with ones that had big challenges, including Dome Petroleum Limited, where he witnessed the power of one financing miscalculation that unravelled at all.

As for riding out the near-term challenges, Nexen is busy drilling additional wells at Long Lake. Its highly profitable U.K. production is set for a 25,500 barrels of oil equivalent per day expansion by 2014. In Yemen, Romanow is confident negotiations "will be resolved." In West Africa, Usan remains on track for first oil next year and more oil is being found in deeper horizons. And in the Gulf of Mexico, Nexen´s discovery with Shell US has the potential to blossom into one of the most significant discoveries in the basin.

With all those irons in the fire, of course, comes risk. But as Romanaow sees it, "If you´re not in the oilsands or you´re not in the deep water or you´re not in risky areas, you´re probably not in the high-hydrocarbon places."

The Great Crew Change: 'Wolf Cries' or Reality?

by Barbara Saunders|Rigzone Staff|Friday, August 12, 2011



For more than a decade, the Great Crew Change has generated deep concern among many – and skepticism among some – in the oil and natural gas industry.

Much like the old story about the boy who cried "wolf" so many times that nobody would listen when the wolf finally was at the door, statistics confirm that the post-World War II "baby boom" generation is at the retirement door.

What remains to be seen is how well the industry on the whole heeded the "wolf cries" to usher in a well-trained new generation of both technical professionals and rig labor, the two areas of greatest perceived need.

Are We There Yet?
Although there is some controversy about whether the Great Crew Change will be all that sweeping, the age statistics are indeed alarming. According to Pete Stark, VP of industry relations for IHS, the peak age for oil and gas technical personnel has risen from 43 in the year 2000 to 50 in 2006. The peak age is expected to be 60 in 2012.

Another way of looking at the situation is about half of the industry will be retiring within the next 10 years.

Retirements in progress mean that "the big crew change is happening now and will be mostly over in five years," according to a 2011 study by Schlumberger Business Consulting. The study projects that by 2014, the inflow of younger petro-technical professionals (PTPs) will be only about 17,000, compared with roughly 22,000 experienced PTPs who are expected to leave by then, for a net shortfall of 5,000.

Other key findings of the study included:
•Demand for graduates is recovering and outpacing the pessimistic forecasts of a year ago. Recruitment targets for technical staff in 2011 are 15 percent higher than levels planned in 2009. National oil companies (NOCs), independents and majors all plan to intensify recruitment efforts from 2011 onwards.
•Universities appear to be on track to provide the oil and gas industry with sufficient graduates in geosciences and petroleum engineering, but supply from "quality universities will remain tight."
•Recruitment targets for PTPs in mid-career are soaring, with NOCs and majors reporting the highest rates of increase. "The labor market for experienced PTPs will be tight over the next three years, resulting in the poaching of staff, salary escalation and higher attrition rates," the study said, continuing: "These staffing issues will have serious consequences on projects and production capacity. Companies contributing to the 2010 survey reported that staffing issues will delay projects and may drive decision makers to take more risk."
Mentoring Key
Meanwhile, the American Association of Petroleum Geologists (AAPG) teamed with the recruiting firm Working Smart in a survey this past May of technical oil company professionals age 55 and over. Of those who responded, the average intended retirement age was 65, with only 23 percent seeking to work beyond retirement age.

Many respondents felt that mentoring younger staff is a key factor in reducing adverse effects of the great crew change. The survey showed that 77 percent of respondents were currently mentoring younger staff.

Mario Carminatti, exploration manager for Brazil's national oil company Petrobras, told an industry conference that 42 percent of the company's geologists and geophysicists have less than five years of experience. "We are countering this by increasing the number of senior geoscientists and even retired professionals who operate as mentors to the younger generation," Carminatti said.

J. Ford Brett, managing director of PetroSkills, says that the price tag could be in the tens of billions for having less experienced technical personnel. If the looming demographics result in approximately 20 percent of the industry's personnel having fewer than five years' experience, Brett calculates that it's reasonable to expect a 20 percent reduction in performance across the board. "To put this into focus, in 2006 the industry spent about U.S. $170 billion on E&P. A 20 percent reduction in performance correlates with an economic cost of approximately U.S. $35 billion," Brett stated in an article for the Society of Petroleum Engineers' Talent &

Alberta's July Petroleum Production 853,910 Bbls, Increase Of 215,937 Bbls Over Month June

Reflecting the sharp increase in Turner Valley oilwell allowables placed in effect on July 1st, Alberta's petroleum production for July 1940 showed an increase of 215,937 bbls over output during June, according to figures compiled by Major F. K. Beach, of the Provincial Department of Lands & Mines. Total July production was 853,910 bbls, compared with 637,973 bbls in June. Turner Valley oilwells produced an average of 26,584 bbls per day during July, compared with 20,357 bbls daily in June.

While the July 1940 production does not quite reach the July 1939 output totaling 877,005 bbls, output for the first seven months of this year is still well ahead of the same period in 1939, From January 1st to July 31st 1940 Alberta production of 4,434,484 bbl was recorded, compared with 4,131,274 bbls in the same period last year.

Following is Major Beach's detailed report of June and July production. As some operators outside of Turner Valley do not report production regularly, output shown for fields other than Turner Valley represent in most cases two or three months yield.

FIELD JUNE 1940 JULY 1940
TURNER VALLEY Limestone oilwells 610,730 824,091
TURNER VALLEY Limestone gaswells 6,009 4,224
TURNER VALLEY Absorption plant gasoline 18,729 19,454
TURNER VALLEY Shallow crude oilwells 515 619
RED COULEE 7, light crude oilwells 980 1,053
WAINWRIGHT 4, heavy crude oilwells 844 206
MOOSE DOME Moose 2 light crude oilwell 166 -
VERMILION Franco Battleview 2 heavy crude oilwell - 3,164
DEL BONITA Terminal Oils 2 light crude oilwells - 399
DINA Dina heavy crude oilwell - 700

TOTALS 637,973 853,910