Iron Energy Blog

CanElson's Growth Plans Continue To Take Shape

2011-10-05T20:09:00.001-07:00

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

2011-09-19T17:57:00.001-07:00

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

2011-09-12T14:14:00.000-07:00

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

2011-09-12T14:13:00.001-07:00

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

2011-08-14T20:52:00.000-07:00

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?

2011-08-14T20:50:00.001-07:00

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

2011-08-02T10:51:00.000-07:00

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

Central Alberta Buying Trinidad Well Servicing Assets

2011-06-11T20:40:00.001-07:00

Central Alberta Well Services Corp. has entered into a definitive agreement to acquire the assets and ongoing operations of Trinidad Well Servicing, the service rig division of Trinidad Drilling Ltd. for total consideration of $38 million in cash, excluding working capital. The transaction is expected to close on June 15.

TWS is a well servicing business operating 22 fully crewed service rigs throughout Alberta, British Columbia and Saskatchewan from key operating bases in Grande Prairie, Red Deer and Lloydminster. The implied value of the transaction is $1.73 million per rig.

The TWS acquisition will boost CWC's service rig count to 64 active rigs, making CWC the sixth largest service rig provider in the Western Canadian Sedimentary Basin, operating one of the youngest and most modern fleets in the industry, the company said.

Trinidad Well Servcing assets and personnel will be integrated into CWC's service rig division and further expand CWC's footprint with an operating base in Lloydminster.

CWC said it has identified operational synergies it believes can be realized from this transaction beginning immediately and expects that those synergies will better enable it to capitalize on growth opportunities and facilitate complimentary acquisitions as the industry consolidates.

Central Alberta has secured written commitments for a new credit facility of $70 million which will consist of a three year committed revolving facility of $40 million and a $30 million non-revolving facility to replace the existing debt facilities of the company. The revolving facility will initially be used to help pay for the acquisition of the Trinidad service rigs and will subsequently be available to assist the company in completing acquisitions, financing capital expenditures and for working capital purposes.

Cash on hand, of approximately $10 million, will also be used to fund the acquisition.

On June 8 at the company’s annual and special shareholders' meeting, shareholders approved the change of name of the company to CWC Well Services Corp. from Central Alberta Well Services Corp. The name change was considered appropriate to better reflect the company's identity and current scope of business activities. The final name change is subject to the completion of certain legal and regulatory approvals.

The stock trading symbol on the TSX Venture Exchange will remain as "CWC".

Well servicing has been an important part of Trinidad's operations for more than ten years and has provided a level of diversification as the company has grown its contract drilling business.

Trinidad said it now operates more than 120 drilling rigs across North America, providing broad geographic diversification and reducing the need for the diversification added by the well servicing division.

"As well servicing has become a less significant part of our overall business, we needed to invest capital to grow this division or to narrow our focus more tightly towards contract drilling," said Lyle Whitmarsh, Trinidad's president and chief executive officer.

"Our growth over past few years has largely been through adding deep, technically advanced drilling rigs and we have developed a reputation as an industry leader in this area. Our decision to sell our well servicing assets reflects our strategy to focus on the deep, modern contract drilling market where returns are generally stronger and where we see opportunities for future growth."

Trinidad's well servicing division has 22 well servicing rigs operating from three centres in Alberta. The well service fleet is made up of two skid doubles, six mobile free standing class III singles, five mobile class III doubles, two mobile class III free standing doubles and seven mobile free standing class II singles.

The company expects to use the proceeds from the sale to fund the growth of its deep, technically advanced drilling fleet or to reduce overall corporate debt. Trindad’s long term debt was $593.68 million as of March 31, 2011.

Savanna Expands Budget

2011-06-02T19:57:00.001-07:00

In the face of substantial, sustainable demand, Savanna Energy Services Corp. has decided to add incremental capital to its 2011 capital budget.

Excluding acquisitions, total committed capital for Savanna’s 2011 expansion (including 2010 carryover) now exceeds $165 million, with the estimated 2011 cash outlay approximating $150 million.

The new capital program includes two TDS 3000 drilling rigs, 12 top drives, three service rigs, one conventional retrofit to 3,600 metres capacity, three service rig retrofits, rental fleet expansion, drillpipe and support equipment and field shop expansion.

Expansion of the TDS3000 rollout is in response to the very strong demand for this efficient rig in both Canada and the United States, the company said. The two incremental rigs noted above are not contracted, however, there are contracts in place for six of the TDS3000 rigs (four now in operation), and based on discussions with customers, Savanna said it fully expects the remaining four newbuilds will be contracted before completion.

Similarly, there are customer commitments to fully utilize the top drives being ordered, with Savanna presently operating four rental top drives to satisfy customer demand. Upon taking delivery of the 12 top drives, Savanna will have over 80 per cent of its drilling fleet so equipped, one of the highest ratios in the industry.

Further expansion and commitment to Savanna's well servicing capacity reflect ongoing demand for workover rigs in the company’s North Dakota base. The expansion also includes completion of a workover rig under construction in Performance Well Services at the time of its acquisition.

Also, the company determined to upgrade one of its two remaining sub-3,000 metre conventional double drilling rigs to 3,600 metre capacity. In addition to enhancing its hookload and horsepower, Savanna said it will be expanding its pump capacity and adding top drive capability. This platform has experienced very strong customer commitment to date, with equally strong expected demand going forward. This rig will be subject to a term contract on completion.

Upon completion of this expanded capital investment program along with prior capital commitments, Savanna's combined workover and drilling fleet in Canada, the United States and Australia will include 54 conventional rigs, 10 TDS 3000 rigs, 24 hybrid CT1500 rigs, eight hybrid CT2200 rigs, four Australian hybrid rigs and five coring/surface setting rigs. On the well servicing side, it will have 49 mobile singles and 56 mobile doubles.

This includes 17 rigs from the acquisition of Silverstar Well Servicing expected to close on or about July 7.

Savanna Acquiring Silverstar Well Servicing

2011-05-28T08:08:00.001-07:00

Savanna Energy Services Corp. has entered into a definitive arrangement agreement whereby it will acquire all of the outstanding shares of Silverstar Well Servicing Ltd. for an aggregate purchase price, based on the volume weighted average share price of Savanna over the last five trading days, of approximately $39.6 million excluding acquired indebtedness (long term debt net of working capital) of approximately $5.5 million.

Silverstar is a well servicing company operating throughout Alberta and British Columbia. The transaction will be effected by means of a court approved plan of arrangement.

If the transaction is completed, shareholders of Silverstar will receive, at their election: (i) 0.12834 of a Savanna common share per Silverstar share (subject aggregate maximum share consideration of 1.99 million Savanna common shares); or (ii) $1.27579 cash per Silverstar share (subject to aggregate maximum cash consideration of $19.8 million) or (iii) a combination of (i) and (ii).

If the holders of Silverstar shares elect to receive an aggregate amount of cash or an aggregate number of Savanna common shares which exceeds the applicable maximums, the amount of cash and Savanna common shares to be received by a Silverstar shareholder shall be adjusted pro rata and the balance shall be paid in cash or Savanna common shares, as the case may be.

The board of directors of Silverstar has considered the plan of arrangement and has determined that it is in the best interests of Silverstar and its shareholders. Completion of the plan of arrangement is subject to regulatory approval, court approval, the approval of the shareholders of Silverstar and other customary conditions.

Shareholders of Silverstar will be asked to approve the transaction at a special meeting of shareholders expected to be held on or about July 7 but in any event no later than Aug. 8. Silverstar shareholders representing approximately 51 per cent have entered into agreements in the support of the transaction with Savanna.

The plan of arrangement will require the affirmative approval by holders of two-thirds of the Silverstar shares that vote in person or by proxy at such meeting.

Silverstar is expected to mail a management proxy circular to its shareholders in the middle of June in respect of the meeting. This circular will contain important information regarding this proposed transaction.

The arrangement agreement prohibits Silverstar from soliciting or initiating any discussion regarding any other business combination or sale of material assets, contains provisions enabling Savanna to match competing, unsolicited proposals and, subject to certain conditions, provides for a termination fee payable by Silverstar of $1.5 million.

Upon completion of this transaction, Savanna will be adding 17 service rigs from Silverstar which will compliment both its existing service rig fleet and the recently announced proposed acquisition of Performance Services Ltd.

Silverstar's fleet is comprised of 13, Class III heavy-duty, mobile, free-standing double workover rigs and four free-standing single workover rigs with an average age of less than four years old. Rig Locator records show all 17 Silverstar rigs are in Alberta this week and 10 of them are at work.

The combined company's operational synergies will position it to capitalize on future organic growth and to make future complementary acquisitions based on the new look of its service division, Savanna said.

Savanna's service rig fleet will expand by 18 doubles and 15 singles with the acquisitions of both Performance and Silverstar taking the total service rig count to 101, which are located throughout Canada, the United States, and Australia. Savanna said it is confident this acquisition will continue to attract experienced, quality personnel to work for one of the largest, most modern service rig operators in western Canada.

Subject to receipt of all required approvals, the transaction is expected to be completed in July.

CanElson Announces N. Dakota Acquisition, Releases Q1 Results

2011-05-25T20:35:00.001-07:00

CanElson Drilling Inc. has entered into a purchase and sale agreement to acquire all of the issued and outstanding units of a private North Dakota driller which owns four drilling rigs operating in the Bakken area of North Dakota.

Under the terms of the purchase and sale agreement with the unitholders of the private company, CanElson will pay total consideration of approximately US$19.3 million consisting of cash and the issuance of common shares of CanElson and assume net debt of approximately $4.7 million, for a total purchase price of approximately $24 million.

Pursuant to the purchase agreement, holders of the private company’s units will receive $2.9 million cash consideration and approximately 3.3 million CanElson shares.

In addition to the four month resale restriction arising under applicable securities law, pursuant to the purchase agreement 95 per cent of the CanElson shares received by the private company unitholders will be subject to resale restrictions.

Of those CanElson shares, 33.33 per cent are subject to a resale restriction of four months, 33.33 per cent are subject to an eight month resale restriction and the remainder are subject to a one year resale restriction.

Pursuant to the acquisition, CanElson will acquire four fully crewed drilling rigs which have been primarily drilling horizontal wells in North Dakota resource plays.

In addition to the four fully crewed rigs, CanElson will also acquire positive working capital estimated at $3 million and spares and spare equipment with an estimated value of $1.5 million. It is expected that key employees and management of the private company will be retained and continue with CanElson.

To further strengthen its presence in North Dakota, CanElson said it may deploy some of its new small footprint ultra-heavy-duty telescoping double rigs to North Dakota depending on customers' demand.

It is anticipated that the acquisition will close on or about June 2. Completion of the acquisition is subject to certain conditions including the finalization of certain due diligence investigations and the receipt of all regulatory approvals, including the approval of the stock exchange.

By the end of the second quarter, including the closing of the acquisition, CanElson will operate a combined rig fleet of 32 (net 29) rigs which includes 18 drilling rigs in western Canada, 10 (net nine) drilling rigs in the United States, two (net one) sub-contracted drilling rigs in Mexico and two (net one) service rigs in Mexico.

"Private Co comes with two triple drilling rigs ideally suited to drill the deeper North Dakota oil resource plays, and two doubles well suited to the shallower North Dakota oil resource plays. In addition to excellent well-maintained rigs, their quality experienced personnel will allow CanElson to get an immediate foothold in the second most active oil drilling state in the United States,” said Randy Hawkings, CanElson's president and chief executive officer, in a news release.

CanElson Services revenues for the first three months of 2011 increased to C$40.95 million from $11.62 million in a year earlier.

Revenues were boosted by the acquisition of Eagle Drilling Services Ltd. on Jan. 28, 2011 (Eagle operated eight modern ultra-heavy-duty telescoping drilling rigs in southeast Saskatchewan) for a total transaction value of approximately $75.4 million.

The company reported a first quarter profit of $6.74 million compared to net earnings of $307,000 for the same three months last year.

The company’s utilization was 82 per cent for the first quarter compared to the industry level of approximately 68 per cent.

"The addition of Eagle and the commencement of a five rig construction program continue to position us in the sweet spot of the resource play market,” Hawkings said.

CanElson also completed completed an equity financing, raising gross proceeds of $40.5 million by the issuance of 9.3 million shares at $4.35 per share and it announced plans to construct five tele-double drilling rigs at an estimated cost of $40 million.

Currently the corporation has contracted and/or received contract advances on four of the five tele-doubles and anticipates receiving a deposit and/or contract on the fifth tele-double drilling rig prior to its deployment.

Savanna Posts Improved First Quarter

2011-05-19T06:46:00.001-07:00

Strong oil prices and increased activity in oil and liquids-rich gas plays lifted Savanna Energy Services Corp.’s profit, cash flow and revenue in the first quarter (see table).

As well, an extended cold winter helped increase overall first quarter utilization rates to levels not seen in several years, the company said in releasing its quarterly results.

These factors led to an increase in operating days, hours and rates in Savanna’s drilling and oilfield services divisions and significantly increased revenues and operating margins in each of the divisions compared to the first quarter of 2010.

“The first quarter of 2011 represented an inflection point for Savanna. Almost ideal operating conditions in Q1 2011 in Canada allowed Savanna to achieve the highest utilization rates the company has experienced since 2006,” said Savanna president Ken Mullen.

“With the Canadian industry strongly focused on developing oil and liquids-rich prospects, demand for our deeper conventional fleet was particularly strong. Hybrid drilling utilization, while muted in comparison, was significantly stronger than during the past four Q1 periods,” he said.

Increased day rates in conventional drilling in Canada reflected the strong demand for Savanna’s deeper rigs and, although not as significantly as in conventional drilling, day rates and margins for the company’s hybrid fleet also improved from the first quarter of 2010.

“The continued disconnect between conventional and hybrid drilling in Canada reflects the overall excess supply of shallow drilling equipment,” Mullen said.

Overall, utilization of Savanna’s Canadian contract drilling divinsion was 62 per cent this year versus 54 per cent in 2010.

Savanna said oilfield services also began showing the positive effects of recent oil-focused drilling, with sharply higher demand, and improved pricing.

In the United States, the company continued to achieve high utilization rates for both drilling and well servicing operations in all areas. The company experienced challenges on its footage contracts in the Permian basin, which hurt both U.S. drilling margins and overall drilling margins.

However, it is anticipated that all footage contracts will be renewed as day work contracts by the end of 2011. This will occur at a time when Savanna’s day work rates in the U.S. continue to gradually increase, with further moderate increases expected on renewals during the remainder of 2011. Strong hourly rates also continued in the North Dakota well servicing operations.

“A full quarter of operating experience with our first two TDS-3000 drilling rigs further reinforced our faith in this platform as a highly competitive entry into a market experiencing strong, sustainable demand, and an equally economic retrofit for our low-utilization CT-1500 hybrid drilling rigs,” Mullen said.

With a minimum of six additional TDS-3000 conversions planned for completion in 2011, Savanna will show significant expansion to its North American fleet.

In addition to the TDS-3000 conversions, Savanna will also start drilling operations in Australia with a fleet of four hybrid drilling rigs in 2011, all incorporating Savanna's patented hybrid drilling capability, and all designed to move and operate 365 days a year. All four of these rigs will be operating by the fourth quarter.

Savanna continues to progress on the rollout of the next two ultra-heavy double rigs for its Marcellus core area.

Most critically, of the 16 rigs included in the current capital program, all but six are already contracted. It is expected that all but the last two Australian hybrids will be contracted by the time they are field-ready.

Savanna also recently announced expansion of its oilfield services division with the agreement to acquire Performance Services Ltd., subject to Performance shareholder approval. Performance has 16 service rigs, 13 of which were built since 2006.

In the first quarter Savanna’s drilling division achieved a 15 per cent increase in the number of operating days with virtually the same drilling rig fleet as the first quarter of 2010.

Also, average day rates rose by eight per cent over the same timeframe which, coupled with the increase in operating days, led to an $8.9 million increase in operating margins in the first quarter versus the corresponding 2010 period.

Of Savanna's deployed fleet of 99 net drilling rigs in the first quarter, 75 operated in Canada, 22 worked in the U.S. and the remaining two were awaiting the start of operations in Australia.

The cold winter in Canada and strong demand for Savanna's high specification deep rated rigs led to the highest utilization quarter in the history of Savanna's Canadian conventional division at 86 per cent (2010 - 73 per cent).

The oilfield services division realized a 20 per cent increase in operating hours, and operating margins increased by $4.9 million in the first quarter of 2011 relative to 2010 with virtually the same average fleet size. Also, operating margin percentages were higher than in the first quarter of 2010.

Of Savanna's deployed fleet of 66 net service rigs in the first quarter, 55 operated in Canada, nine operated in the U.S. and the remaining two were located in Australia.

Savanna's Canadian well servicing division had its highest utilization quarter since the first quarter of 2008 and both the U.S. well servicing division and oilfield rentals division achieved higher activity levels and operating results compared to the first quarter of 2010.

Extreme rainfall in Australia halted operations and led to flooding damages on Savanna's two service rigs in that country at the beginning of 2011.

One of the damaged rigs was fully repaired and resumed operations in March. Repairs to the second rig have begun and it is expected to be operational by next month. The operating delays led to negative operating margins and cash flows in Australia in the quarter, but Savanna expects improved operating margins from its Australian operations in the second quarter.

Savanna Energy Services Corp.
Financial Summary
(Million $)

Profit Profit Per Share Cash Flow Cash Flow Per Share Revenue Capital Expenditures

Three Months Ended March 31

2011 (Note 1) $15.58 $0.20 $44.97 $0.57 $168.59 $42.73
2010 (Note 1) $10.57 $0.13 $30.01 $0.38 $130.07 $17.03

Three Months Ended March 31

2010 (Note 2) $9.60 $0.12 $28.21 $0.36 $130.07 $16.43
2009 (Note 2) $3.61 $0.06 $16.77 $0.28 $93.79 $25.73
2008 (Note 2) $25.59 $0.43 $48.01 $0.82 $149.16 $16.82

Note 1 = IFRS accounting

Note 2 = GAAP accounting

Precision Lifts Budget To $790 Million, Plans 16 More Rigs

2011-05-14T11:39:00.001-07:00

By James Mahony

Canada's largest contract-driller will add 16 more rigs to its fleet, raising capital spending 54 per cent in the process.

At its annual meeting in Calgary, Precision Drilling Corporation executives said yesterday the company would expand its new-build program to 28 Super Series drilling rigs from the 12 rigs announced earlier. At the same time, the contractor will boost this year's capital spending to $790 million from the $514 million previously announced.

Of the 16 new rigs announced yesterday, three are Super Singles destined for Canada, and 13 will be Super-Triples headed for the United States.

In the broader group of 28 new rigs planned, 17 are contracted, while the company has "firm commitments" for most of the other 11 rigs.

Higher spending on rig iron is underpinned by Precision's optimism about the near-term strength of the North American onshore drilling market. "We expect summer activity to look very good," said Kevin Neveu, Precision president and chief executive, adding that he expects this summer's drilling to be the highest in several years.

"I am particularly pleased to see strong market demand for the Super Triple rig in the Bakken and Eagle Ford plays, with 13 of today's announced new builds slated for those oil and natural gas liquids rich plays," he said.

South of the border, rig counts are near historic highs, with many producers targeting oil, he said. Yet, as recently as 2006, three-quarters of Precision's drilling rigs were targeting natural gas, while just over half of its rigs were pursuing gas in 2009. About 80 per cent of the company's rigs drill horizontal or directional wells today.

This year's capital spending, which includes $121 million for sustaining and infrastructure spending, is based on currently-expected activity levels for 2011. Another $458 million is slated for expansion capital for new-build rig programs.

This year's total capital expenditures also include the cost of upgrading eight to 12 rigs and purchase long lead-time items for future rigs or upgrades at an expected cost of $211 million. Certain rig upgrades will depend upon the completion of term contracts before incurring planned spending.

Precision expects the $790 million total will be split $718 million between its contract drilling division and $72 million for its completion and production services division.

To complete its 2011 new-build rig program and the planned upgrades, Precision expects there will also be an additional $152 million of capital expenditures incurred in 2012.

The drilling contractor has not yet resolved a $216 million tax claim being pursued by the Canada Revenue Agency (DOB, Feb. 11, 2011). In 2005, Precision sold its Energy Services and International Drilling divisions to Weatherford for about US$2.28 billion in stock and cash. The CRA ultimately re-assessed the deal and the tax owing by Precision, giving rise to the $216 million tax bill.

So far, Precision is treating the CRA claim as a contingent liability. In its 2010 annual report, the company said income tax of as much as $350 million could ultimately be payable by the company, under certain circumstances (the figure includes, but is not limited to, the CRA's $216 million tax claim). At the end of the first quarter, Precision's long-term debt stood at about $811 million.

Yesterday, Neveu said management remains confident in advice it has received that its chances of success in challenging the CRA's $216 million claim are strong. Earlier, the company pledged to pursue that challenge through Canada's appeal courts, acknowledging the task could involve years of litigation.

AKITA Looks Beyond Gas Price For Stimulus

2011-05-10T10:50:00.001-07:00

By James Mahony

While a recovery in natural gas prices would be welcome news in the drilling sector, a boost could also come from other quarters, an executive with AKITA Drilling Ltd. said after the company’s annual general meeting in Calgary yesterday.

Murray Roth, AKITA‘s vice-president of finance and chief financial officer, said state-owned producers from abroad looking to build gas supply in Canada could give added stimulus to Western Canada’s drilling sector through joint ventures, for example.

The pursuit of liquids-rich gas reserves by Canada’s domestic producers is also providing a shot in the arm, helping contractors like AKITA, he said.

In the first quarter, AKITA’s earnings rose more than 1,000 per cent, testifying to the strength of a recovery that began as far back as last year’s first quarter, company executives said. Revenue advanced 31 per cent and funds flow from operations increased 79 per cent from last year’s comparable figure.

The company reported 2,017 operating days for its rigs in the three months ended March 31, 2011, up from 1,701 operating days a year earlier.

Due to slow market conditions AKITA exchanged with a joint venture partner in Alaska during the first quarter and took possession of one complete rig and then relocated the rig to Canada. The heavy capacity double rig is being retrofitted to make it competitive in a non-arctic market.

During yesterday’s meeting, shareholders heard AKITA would extend the depreciation period on the drilling rigs and equipment that comprise most of its assets. In recent years, steadily-rising depreciation has taken a toll on earnings.

Previously, AKITA’s drilling rigs were depreciated in 2,000 operating days, while the company will now depreciate equipment over 3,600 operating days. In the short run, the change is expected to boost earnings, since depreciation will take a proportionately smaller bite out of total costs booked in each reporting period.

AKITA is staking much of its future on the success of pad-drilling, and currently counts 11 pad-drilling rigs among a 35 total drilling rigs. By year-end, the Calgary-based contractor will add three more pad-drilling rigs to its fleet, and finish 2011 with 39 rigs in all.

According to Roth, pad-drilling rigs can cost $15 million to $20 million each, but better economics and a smaller environmental footprint makes them strong competitors in Western Canada’s drilling market. Heavy oil and steam-assisted gravity-drainage (SAGD) wells are a mainstay for such rigs, he said, adding that two of the company’s pad-drilling units are also drilling for potash in Saskatchewan.

Management said conventional rig activity and rig rates showed marked increases in the first quarter, compared to 2010, while the company’s increased number of pad rigs contributed to the overall increase in quarterly revenue. The revenue boost went against the year-over-year, first-quarter declines in revenue the company had seen in the last four years.

AKITA executives said the company has made a concerted effort to improve its retention of employees by, for example, offering new employees, including rig workers, participation in the company’s pension plan.

In the three months ended March 31, 2011, AKITA’s net income rose to $7.95 million or 44 cents per share from $720,000 or four cents per share in the first quarter of 2010. Funds flow from operations in the quarter climbed to $13.71 million per share from $7.64 million in the 2010 quarter. Revenue rose to $57.44 million from $43.97 million in the earlier period, while capital spending advanced to $11.13 million from $4.48 million in the first quarter of 2010.

Year *Profit Profit/ *Cash C.F./ *Revenue *Capital
Share Flow Share Expenditures
First Quarter
2011 $7.95 $0.44 $13.71 $0.76 $57.44 $11.13
2010 $0.72 $0.04 $7.64 $0.42 $43.97 $4.48

* Millions of Dollars

North America In Early Stages Of Long-Term Oil Growth Cycle: Precision

2011-04-28T06:51:00.000-07:00

By Richard Macedo

The head of Precision Drilling Corporation said on Tuesday that it appears North America is in the early stages of a long-term oil growth cycle.

The driller, which announced first quarter results yesterday, increased its revenue and net income with most of its rigs drilling for oil or liquids-rich natural gas across North America during the three-month period. The company also announced an increase in its capital budget to build new rigs (DOB April 26, 2011).

Drilling rig revenue per utilization day in Canada climbed to $17,820 in the first quarter from $15,511 during the same period last year.

"[It] demonstrates the pricing power Precision enjoys in this market," Kevin Neveu, president and chief executive officer, said during a conference call discussing first quarter results. "We continue to see a large backlog of work that was not started this winter.

"We have several clients working with us to secure crews through the summer, fall and next winter drilling season. We've already begun to reserve rigs for the fall."

This suggests a continuation of the strong oil-driven momentum through the summer of 2011 and into the winter of 2012, Neveu said, adding that, "we are likely in the early innings of a sustained, long-term oil growth cycle for Canada and for North America."

He said he doesn't see evidence of an industry over build right now.

"If you look back over the last 10 years...the large cap oil service drillers have been very disciplined in their new build programs, building generally against customer need," he said. "Our industry and our peers are all building into contracts or into high certainty.

"There are financial curves which in some cases are a little wider, some cases a little narrower. Our curves are very narrow."

Meanwhile, there have been questions about the impact of a high snowpack and wet spring due to a prolonged winter, but Neveu said it's a low concern for the company.

"The snowpack is well above average," he said. "The long winter delayed the thaw and we expect very wet conditions with the prolonged spring break-up.

"Nonetheless, we expect to have more rigs running compared to last year and whatever work is delayed by the wet conditions likely increases Precision's Q3 utilization."

Neveu also said another concern being raised is the ability to staff rigs during times of high activity.

"My response is the same as always: it's our job to staff our rigs with the appropriate levels of skill and experience," he said. "We have a variety of internal systems and processes to meet this challenge. While I know it's not easy, I also know that our people are dedicated and completely focused on this issue.

"You will not hear Precision complaining about people shortages. In fact, ultimately, an industry human resource shortage should result in good opportunities for Precision and may further enhance our pricing power."

Interest remains strong for additional Tier 1 Super Series rigs in the United States. Precision believes that customer demand, specifically for the Bakken, Eagle Ford and Permian Basin, will result in additional new build rig opportunities throughout 2011 and the company continues to see attractive opportunities to upgrade lower tier rigs.

"We continue to see new build economics in all three regions and are currently in the final stages of negotiating contracts with several customers for multiples of new build 1,500 horsepower Super Triple rigs," Neveu said. "If successful, all of these rigs will be deployed in the U.S. later this year.

"In June, we'll be opening our new Houston technology centre," he added. "This facility brings Precision's full rig maintenance, crew training and rig construction capabilities into play in the United States."

Oil plays in Canada, such as the Cardium and Viking, will also provide additional opportunities for new build rigs during the year.

Savanna To Acquire Performance Services

2011-04-26T15:06:00.000-07:00

Savanna Energy Services Corp. has entered into a definitive arrangement agreement to acquire all of the outstanding shares of Performance Services Ltd. for a total consideration of 3.56 million common shares of Savanna.

Based on the volume weighted average price over the last five trading days, the total purchase price is approximately $35.28 million.

Performance is a well servicing company operating 16 mobile freestanding service rigs throughout Alberta, British Columbia and Saskatchewan. Performance has no debt and will have approximately $2 million of working capital at the closing date of the transaction. The transaction will be effected by means of a court approved plan of arrangement.

The board of directors of Performance has considered the plan of arrangement and has determined that it is in the best interests of Performance and its shareholders. Completion of the plan of arrangement is subject to regulatory approval, court approval, the approval of the shareholders of Performance and to other customary conditions.

Shareholders of Performance will be asked to approve the transaction at a special meeting of shareholders expected to be held on or about May 31 but in any event no later than June 29. The transaction will require the affirmative approval by holders of two-thirds of the Performance shares that vote in person or by proxy at such meeting. Performance is expected to mail a management proxy circular to its shareholders on or about May 9 in respect of the meeting. This circular will contain important information regarding this proposed transaction.

Savanna said its combined company's operational synergies will position it to capitalize on future organic growth, and will also put the company in a good position to make future complementary acquisitions based on the new look of its service division.

These 16 service rigs will take Savanna’s total service rig count to 84 rigs which are located throughout Canada, the U.S., and Australia.

Subject to receipt of all required approvals, the transaction is expected to be completed in early June.

Trinidad Building New Rigs And Raises Capital Budget

2011-04-15T15:40:00.000-07:00

Trinidad Building New Rigs And Raises Capital Budget
Trinidad Drilling Ltd. says it has agreed to build two new rigs for delivery into operations in 2011.

"Demand for high quality, modern equipment has continued to increase and contract terms have now moved to a point where it is attractive for us to build new equipment," said Lyle Whitmarsh, Trinidad's president and chief executive officer in a news release.

"The rigs we are adding to our fleet fit well with our strategy of deep, technically advanced equipment and we expect that they will remain competitive long after their initial contracts expire."

Rig No. 139 will be an 18,000 foot (5,500 metre) triple rig with 1,500 horsepower and equipped with Trinidad's industry-leading technology and automation. The rig is expected to cost approximately $18 million and be operational in the Eagle Ford shale in Texas in the second half of the year. The rig is backed by a three-year, take-or-pay contract that guarantees 100 per cent utilization throughout the duration of the contract.

Rig No. 57 will be an 18,000 foot (5,500 metre) triple rig with 1,500 horsepower and is being built to work in Steam Assisted Gravity Drainage (SAGD) applications in northeastern Alberta.

In addition to Trinidad's usual automation and technical advancements, this rig will include a system that provides improved fluid handling ability while drilling in a pad environment, and a new pipe handling system that removes the need for a crew member to be positioned in the derrick, increasing both the performance and the safety of the rig's operations.

Trinidad expects that it will cost approximately $20 million to build the rig and that it will be operational towards the end of 2011. The rig is under a four-year, take-or-pay contract that guarantees a minimum of 1,200 days over a four year period which equates to an 82 per cent average utilization over the term of the contract.

In addition to these two newly-announced rigs, Trinidad is currently building a natural gas powered rig for operations in the Horn River in northeastern British Columbia.

The company expects that the construction of the three new rigs, completion of the 2010 rig construction program and capital enhancements planned for a small number of existing rigs will total approximately $80 million of capital expenditures in 2011.

Following the completion of the rigs being constructed in 2011, Trinidad will have 122 drilling rigs with 62 rigs in the U.S., 57 rigs in Canada and three rigs in Mexico.

In addition, Trinidad has 22 service rigs, 20 preset and coring rigs and five barge drilling rigs

-Nickels

Oilfield Theft

2011-04-09T20:34:00.000-07:00

News Calgary & Alberta
Cops to target oilfield thieves
By Katie Schneider, Calgary Sun

Last Updated: January 8, 2011 11:25pm

StoryCommentsEmail StoryPrintSize A A AReport Typo.Mounties in Alberta are getting tough on oilfield thiefs after an increasing number of their crimes have plagued Strathmore and other rural areas in the last year.

Next week, RCMP from Strathmore and surrounding areas including Calgary, along with representatives from the oil and gas industry will discuss what more they can do to combat the growing problem of break and enters and thefts from well sites, said Const. Clint Chisan.

“It’s coming up with a more co-ordinated effort to combat it,” he said.

“There is more we can do to share information to determine what resources we can put forward.

“There have been arrests made, but we need to do more.”

In the past year, RCMP have investigated more than 40 well site thefts in the Stathmore area alone.

Private contractors who build compressor stations are often the targets of the thieves who break in to steal tools and equipment, said Chisan.

“They are often the victims of the crime as well,” he said.

“We are talking about hundreds of thousands of dollars over the past year.”

Suspects involved in the break and enters have been linked to other property crimes in rural areas, including thefts to construction sites, rural homes and businesses, vehicle and copper wire.

Surveillance video has caught suspects in several of the incidents, but RCMP still need help identifying them.

Most recently, on Dec. 14, four masked suspects, including one female, were caught on video breaking into a site east of Standard, about 80 km east of Calgary.

They fled in a light coloured Dodge Crew Cab truck with body damage to the driver’s side door.

The female is about 200 pounds, 5-foot-6, walks with a limp and was wearing a black and grey striped coat.

On Nov. 21, a man was seen on surveillance video breaking into a compressor station site near Beiseker, about 70 km northeast of Calgary, and fleeing in a light coloured Ford F-Series Xtra-Cab truck.

Anyone with information about these crimes is asked to call Strathmore RCMP at 403-934-3968 or Crime Stoppers at 1-800-222-8477.

katie.schneider@sunmedia.ca

Western Energy Acquiring Stoneham For $245 Million

2011-04-09T20:31:00.000-07:00

Western Energy Services Corp. and Stoneham Drilling Trust have entered into an agreement to combine to create the sixth largest contract driller in Canada with 43 rigs available for work.

Subject to certain conditions, Western will acquire all of the issued and outstanding units of Stoneham in exchange for a combination of cash and Western common shares.

Under the terms of the transaction, Stoneham unitholders will, for each unit held, receive at their election: (i) 61.538 Western common shares; or (ii) $24 in cash, subject to a maximum of $115 million in aggregate cash paid.

Assuming all Stoneham unitholders elect all cash, each Stoneham unitholder would receive approximately $14.41 in cash and 24.577 Western common shares for each Stoneham unit held.

The Western share consideration offered to Stoneham is equivalent to $24 per Stoneham unit based upon a deemed value per Western share of 39 cents and represents a 41 per cent premium to Stoneham's 20-day volume weighted average trading price of $17.03 per unit as at April 7, 2011. The total transaction value is approximately $245 million, including the assumption of approximately $53 million in debt and transaction costs.

Assuming the maximum cash consideration is elected, upon completion of the transaction current Western shareholders will own approximately 84 per cent of the combined entity and Stoneham unitholders will collectively own approximately 16 per cent, on a fully diluted basis.

The transaction is expected to be completed by way of a Plan of Arrangement under the Business Corporations Act (Alberta) and is subject to normal stock exchange, court and regulatory approvals and the approval by at least 66 2/3 percent of the outstanding units of Stoneham voted at a special meeting of unitholders of Stoneham to vote on the transaction which is expected to be held in mid June.

The deal has received unanimous approval by the board of directors of Stoneham Administration Inc., the administrator of Stoneham and unitholders of Stoneham, holding approximately 35 per cent of the outstanding Stoneham trust units, have entered into lock up agreements to vote in favour of the transaction.

Due to the proposed transaction, the Stoneham board has determined to terminate and cancel its substantial issuer bid. As such, Stoneham will not accept for purchase or pay for any units deposited under the SIB.

Stoneham has assembled one of the premier deep capacity drilling rig fleets in the industry. Its rig fleet consists of 19 drilling rigs, all of which are Efficient Long-Reach ideally suited for deep horizontal drilling in the capital intensive resource plays such as the Cardium, Bakken, Viking, Shaunavon, and Montney formations as well as the Peace River heavy oil area.

Stoneham has one of the highest utilization rates in the industry for the three months ended March 31, 2011. Preliminary Rig Locator records for the first quarter show the company's Canadian rigs had a 69 per cent utilization rate in the first quarter with 71 wells drilled. Western's Canadian rigs drilled 136 wells and had a 59 per cent utilization rate.

Average age of Stoneham's fleet is six years, with approximately 37 per cent of the fleet added in the last four years.

A combination with Stoneham would solidify Western as a premier contract driller in the deep horizontal drilling market. Pro forma Western would emerge as having one of the largest deep capacity modern fleets in Canada at a time when this type of equipment is in exceptionally high demand, the company noted.

Western continues to focus its efforts in three core business lines encompassing contract drilling through Horizon Drilling Inc., service rigs and rental and production services with an emphasis on businesses engaged in unconventional resource development. Stoneham's assets, client base, operational personnel, safety and operational performance meet Western's acquisition criteria perfectly, the company said.

"This transaction represents a significant milestone in Western's growth achievements," said Western chief executive officer and chairman Dale Tremblay in a news release. "Stoneham has assembled one of the highest quality, deep capacity drilling rig fleets in Canada. With one of the top tier teams in the industry, Stoneham has earned the reputation as a premier contract driller which is evidenced by its blue chip safety record, high quality service and top utilization rates."

Combining the Stoneham fleet with Western's own rigs will give Western a 43-rig fleet and establish Western as the sixth largest contract driller in Canada. The combined fleet will consist of 90 per cent "ELR" rigs which are ideally suited for horizontal drilling in the key resource plays in Western Canada, Tremblay said.

The combination of Stoneham and Western will create one of the top contract drillers in the country, said Bruce Jones, Stoneham's president and chief executive officer.

"This transaction gives our unitholders an immediate premium, immediate liquidity and the option to take shares in an exciting high growth vehicle. We thank our staff for their dedication and hard work that has led to this success."

Incrementally Western said it expects to achieve significant operational synergies over the next 12 to 18 months.

Stoneham has agreed that it will not solicit or initiate discussions regarding any other business combination or sale of material assets. Stoneham has also granted Western the right to match any superior proposals. The transaction provides for a reciprocal non-completion fee of $8 million payable in certain circumstances if the transaction is not completed.

Cormark Securities Inc. is acting as exclusive financial advisor to Western with respect to the transaction.

National Bank Financial Inc. is acting as exclusive financial advisor to Stoneham and has provided Stoneham with a verbal opinion that, subject to its review of the final form of the documents effecting the transaction, the consideration to be received by the Stoneham unitholders pursuant to the transaction is fair, from a financial point of view, to the Stoneham unitholders.

Stoneham Reports Profits

2011-03-28T15:42:00.000-07:00

Stoneham Drilling Trust has announced a fourth consecutive quarter of solid financial results due to higher utilization causing a significant increase in revenue, net earnings and cash flow from operations than were earned in the fourth quarter of 2009.

The trust said it continues to be cautiously optimistic with respect to demand for contract drilling services in 2011. To date in 2011, the strong demand for Stoneham’s services has continued which allowed the trust to realize price increases in the first quarter.

“However with the majority of our fleet participating in the spot market, we remain cautious in our outlook for the second half of 2011. We continue to be concerned about the factors influencing both the demand for and the supply of natural gas and the potential for continued downward pressure on natural gas prices,” Stoneham said in a news release.

Operating days rose in the fourth quarter of 2010 in both Canada and the U.S. to 1,187 days from 885 days a year earlier as a result of continued increased demand for contract drilling services. In Canada, Stoneham surpassed the industry average of 49 per cent with a 67.9 per cent utilization in the quarter.

In Canada, the trust booked 1,064 operating days for the three months ended Dec. 31, 2010, up from 802 the previous year.

Revenue in the fourth quarter grew 76 per cent from prior year to $31.9 million as a result of increased operating days, improved dayrates in Canada, and higher cost recoverable charges partially offset by lower dayrates in the U.S. and a weaker U.S. dollar.

Revenue per day rose 31 per cent to $26,915 from $20,498 earned in the fourth quarter of 2009.

Cash flow from operations more than doubled from prior year to $8.8 million in the fourth quarter of 2010, while net earnings and comprehensive income rose by $3.8 million to $4.5 million.

Stoneham’s higher revenues were partially offset by increased operating expenses, which grew by 76 per cent due in part to the higher activity. On a per day basis operating expenses increased 32 per cent to $17,741. The rise in daily variable operating expenses was caused by an increase in crew wages effective Oct. 1, 2010, higher repairs and maintenance expenses and increased cost recoverable charges. The fixed cost component was also higher due to higher compensation costs associated with the trust’s operations centre in Leduc and higher training and education costs for rig crews.

General and administrative expenses increased nine per cent year over year due to higher compensation costs and stand-by charges on Stoneham’s credit facilities. Amortization expense was essentially unchanged in the quarter despite the increased activity levels as a result in the change in estimate of the useful lives of rig equipment, which lowered per operating day amortization.

Lower average debt levels resulted in a somewhat reduced interest expense despite a 75 basis point increase in the Canadian prime interest rate. Future income tax expense rose in the fourth quarter due to an increase in the cumulative temporary differences between the accounting and tax values of property, plant and equipment.

Capital expenditures totaled $0.4 million in the quarter and $6 million of long-term debt was repaid.

On Dec. 6, 2010, the trust's board of directors announced its intention to convert to a corporation at its annual general and special meeting to be held on June 9, 2011.

The trust announced on Dec. 16, 2010, the acceptance by the TSX of its normal course issuer bid application. As at Dec. 31, 2010, the trust had repurchased 9,964 trust units for $0.1 million. These trust units were cancelled in January 2011.

Subsequent to the year end, Stoneham announced its intention to repurchase up to 300,000 of its units through a substantial issuer bid (SIB). It repurchased a further 35,420 trust units for $0.5 million under the NCIB subsequent to year end. The NCIB was suspended on Jan. 31, 2011 coincident with announcement of the substantial issuer bid. On March 14, the trust announced a variation and extension to its SIB, extending the offer to 1:00 p.m. (Calgary time) on April 7.

Improved demand for contract drilling services, and more specifically oil and liquids rich natural gas related drilling, resulted in significantly higher operating days and utilization rates last year in Canada. Stoneham continued to deliver industry leading utilization exceeding the industry average rig utilization rate by 45 per cent for the year as reported by the Canadian Association of Oilwell Drilling Contractors (CAODC).

In Canada, Stoneham booked 3,648 operating days last year, up 76 per cent from 2069 days in 2009.

In the U.S. operating days in 2010 decreased slightly with Rigs 17 and 18 being deployed to the Bakken play of North Dakota from the Anadarko Basin in Oklahoma. In 2009, Rig 11 was active in Oklahoma until it was redeployed to western Newfoundland in June.

In Canada, the remaining long-term contract expired during the fourth quarter. As a result, all Canadian rigs now participate in the spot market in anticipation of increased activity levels.

Stoneham said its customer's drilling program in western Newfoundland has been completed and it anticipates deploying the rig to the U.S. to participate in the Bakken play during the second quarter of 2011.

In the U.S., the contract for Rig 17 has been extended for a third six month term expiring September 2011. The contract for Rig 18 has also been extended for a second year and will expire in April 2012.

For the year ended Dec. 31, 2010, revenue rose substantially from 2009 as a result of higher operating days, improved dayrates in Canada (in part because more rigs were operating under term contract dayrates in 2010), stand-by and contract termination revenue recognized throughout the year, and higher cost recoverable charges, partially offset by lower dayrates in the U.S. and a weaker U.S. dollar.

During the year, $5.1 million of stand-by revenue was recorded as a result of shortfalls in contracted operating days and the termination of one of its long-term contracts. In 2009, $1.3 million of stand-by revenue was recorded. Revenue per operating day averaged $25,753 in 2010, up eight per cent from $23,942 in the prior year.

The majority of the trust’s operating expenses are variable in nature and adjust with activity levels. Consequently, operating expenses in 2010 increased 70 per cent to $69.7 million in 2010, due to higher operating days, increased cost recoverable charges, and higher planned major maintenance expenditures throughout the year as a result of improved activity levels. Operating expenses per day increased three per cent to $16,923 from $16,357 in 2009.

Cash flow from operations and net earnings grew substantially in 2010 to $26.7 million and $12.4 million, respectively. The increased activity levels and revenue were partially offset by somewhat higher costs in all major categories attributable to the rise in activity year over year.

In 2011, Stoneham said it anticipates revenue, net income and cash flow from operations will be comparable to that earned in 2010.

Rig Summary For Stoneham Drilling Trust

Wells Drilling Rigs Operating Days Average Days Per Well Average Metres Per Well Rig Utilization

Three Months Ended December 31

2010 58 17 901 15.5 2,261 57.61%
2009 37 17 697 18.8 2,337 44.57%
2008 50 16 1,027 20.5 2,251 69.77%

Twelve Months Ended December 31

2010 180 17 3,096 17.2 2,700 49.90%
2009 88 16 1,641 18.6 2,553 27.31%
2008 151 17 3,283 21.7 2,491 53.99%

* Average fleet size during the period

** Number of unique wells worked on during the period

Note: Experimental Wells were not tracked prior to August 2006. Excludes resumption and re-entry wells.

Year *Profit Profit/ *Cash C.F./ *Revenue *Capital Distributions Distributions
Unit Flow Unit Expenditures Paid/Declared /Unit
Fourth Quarter
2010 $4.48 $0.56 $8.85 $1.10 $31.95 $0.36 $0.00 $0.00
2009 $0.69 $0.09 $4.12 $0.51 $18.14 $0.03 $0.00 $0.00
2008 $8.88 $1.11 $12.69 $1.58 $37.07 $0.70 $2.41 $0.30
2007 $4.99 $0.62 $7.68 $0.96 $26.04 $10.67 $3.01 $0.38
Fiscal Y.T.D.
2010 $12.37 $1.54 $26.72 $3.33 $106.10 $5.47 $0.00 $0.00
2009 $0.86 $0.11 $9.55 $1.19 $60.02 $0.34 $0.80 $0.10
2008 $14.98 $1.87 $27.07 $3.37 $112.69 $8.65 $11.43 $1.43
2007 $6.00 $0.75 $17.25 $2.15 $65.92 $52.12 $13.84 $1.73
* Millions of Dollars

Higher Oil Prices Boost Conventional Activity

2010-10-08T17:09:00.000-07:00

Source: Profiler
Higher oil prices boost oilsands and conventional activity, while natural gas producers continue to face challenges
By Jim Bentein

The massive oil spill in the Gulf of Mexico, caused by an explosion on a BP offshore platform that occurred in mid April, will lead to a shift towards more oilsands development in Canada, says a Houston-based energy industry consultant.

Robert Peterson, a vice-president with Charles River Associates (CRA), predicted that the explosion, which killed 11 workers on Transocean’s Deepwater Horizon rig and caused a spill that threatened the shorelines of several southern U.S. states, will lead to a moratorium on drilling in the Gulf, where 25 per cent of U.S. oil and gas supplies come from.

Peterson, who specializes in the oilsands sector, said that as a result, the spill will likely lead to U.S. politicians not allowing offshore development in the Pacific or the Atlantic, where U.S. President Barack Obama recently lifted drilling restrictions.

“The Gulf of Mexico incident will also lead to a moratorium on drilling in the Gulf of Mexico that will last one or two years, during which the details of the catastrophe will need to be better understood,” he noted.

He said the most likely outcome is that concerns about “dirty oil” from the oilsands will fade into the background.

“Suddenly heavy oil, which was viewed as a dirtier oil because of its higher carbon content, looks a lot safer than oil from offshore.”

He predicted the disaster may also restrict the development of offshore oil and gas in Atlantic Canada.

After the 2008 credit crisis hit, several oilsands projects were postponed. But the sector has started to make a comeback, one that Peterson thinks will only accelerate as a result of the disaster in the Gulf of Mexico.

He predicts U.S. federal legislation that might have targeted oilsands crude will now be on the backburner, as U.S. lawmakers begin to realize the country, which imports a total of over 11 million barrels a day (bbl a day) of crude and liquids, 57 per cent of its needs, is able to rely less on offshore production.

“There could be a significant shift to the oilsands,” he said.

CRA believes oil prices will be somewhat volatile but will average in the $70 a barrel range, which Peterson said provides for a good return.

“Supply costs [to develop oilsands projects] are down somewhat but it is still costing $55 to $60 a barrel to develop projects,” he said. “That still provides for a good, solid return. It’s like investing in a 30-year annuity.”

Peterson predicts the environmental performance of oilsands operators will only improve, as oilsands miners improve their tailings management and water use and steam assisted gravity drainage (SAGD) operators improve the technology.

He also believes environmentalists will now shift their attention to offshore production. “After all, look what can happen offshore, compared to the known of on-land development.”

Peter Howard, president of the Calgary based Canadian Energy Research Institute (CERI), said he wouldn’t disagree with Peterson’s view that the focus of the environmental movement will now shift from the oilsands to offshore energy development, but he’s also not as sure that will lead to a ban on new drilling in the Gulf.

“If [President Obama] puts a ban on offshore drilling, his energy security policy will go out the window,” said the CERI head. “What I could see is the development of a new offshore protocol, where a relief well needs to be drilled before companies drill into their target areas.”

That would drive up the cost of offshore development.

He agrees with Peterson that offshore development in the Atlantic and the Pacific is likely to be prohibited.

All things being equal that should lead to a spurt of oilsands development, he said, except there are signs labour and material costs are “creeping up again,” after they dropped 15 per cent and more during the Great Recession.

As a result, Howard believes only larger, cash-rich companies will look at new projects, beyond what is already known.

CERI has forecast oilsands production will reach about three million bbl per day by 2020, and Howard believes that will still be the case. But it also believes there will be a new spurt of development from 2020 through to 2040, when oilsands output will hit 4.4 million bbl per day.

OILSANDS RESURGENCE

Oilsands project planning and development has escalated since the 2008 financial collapse. Cenovus Energy announced plans earlier this year to spend US$500 to US$600 million to increase production from its SAGD projects. Devon Energy revealed plans to build a third phase of its Jackfish project, which would take total production above 100,000 bbl per day, and also announced it was spending $500 million to acquire 50 per cent of BP’s interest in the Kirby oilsands project, which the two plan to expand to as much as 170,000 bbl per day.

BP announced plans in March to partner with Calgary-based junior Value Creation to develop the firm’s Terre de Grace in situ project; China Investment said it will invest $817 million to develop oilsands assets held by Penn West Energy in the Peace River area; and Husky Energy has completed front-end engineering for its proposed 60,000-bbl-per-day first phase of the Sunrise project (BP is a partner).

In addition, Suncor Energy is proceeding with a 62,500 bbl per day expansion of its Firebag SAGD project and there have been a number of smaller announcements regarding SAGD projects.

Oilsands mining projects are starting to move ahead as well, with Imperial Oil spending $8 billion on phase one of its Kearl project, which will produce 110,000 bbl per day (it would eventually produce 354,000 bbl per day) and Royal Dutch Shell is well underway with the 100,000 bbl per day expansion of its Athabasca Oil Sands Project, which would lift production to over 265,000 bbl per day.

CRA has been predicting total oilsands production will reach three million barrels a day by 2020, from about 1.5 million a day now. But the offshore catastrophe may lead to an increase in that forecast, Peterson said.

As for the conventional oil sector, production will get a boost because of the growth of shale oil plays such as the Bakken, but even at that Howard said CERI doesn’t see production reaching much more than 200,000 bbl per day, up from about 70,000 to 80,000 bbl per day now.

CERI believes oil prices will average between $77 and $81 West Texas Intermediate this year.

NATURAL GAS

While most paint a bright picture for oil development in Canada, the country’s natural gas sector still faces challenges. The problem is that North America is awash in the stuff, thanks to the advance of horizontal drilling and other technologies that have unlocked huge shale and tight gas resources.

Calgary-based Canadian Society for Unconventional Gas (CSUG) released a report in May that illustrates just how much gas there is in Canada—and supplies are even more impressive in the United States.

The report concluded that Canada’s natural gas in place resource is almost 4,000 trillion cubic feet, with the marketable portion being 700 to 1,300 tcf.

A recent report by the U.S. Potential Gas Committee, which looked at the natural gas potential in the Lower 48 states, reached the same general conclusion, predicting that there are 1,836 tcf of technically recoverable gas resources in those states.

CERI’s Howard said that means natural gas prices will stay in a range of $4 to $6 per mcf for many years.

“The shift will be towards resource plays, such as shale gas,” he said. “Only the big companies with deep pockets can afford to go there, since it requires economies of scale. Unfortunately, that creates a problem for small companies.”

Juniors will try to survive by developing the “edge plays,” mostly shallow gas reserves that larger companies find uneconomic.

“But what if a junior invests in a shallow play and the next year gas prices drop to $3 per mcf?”

He predicts there will be a good deal of merger and acquisition activity, as companies have to grow larger to survive.

“One of the big challenges faced by gas producers is what it can do as an industry to create new markets,” added Peterson.

The best immediate potential market is in the conversion of coal-fired power plants in the United States to cleaner-burning gas, since about half of the electricity in the United States is produced by coal-fired plants.

But he said the “coal lobby” in the United States is preventing this from happening. As a result, CRA also sees natural gas prices ranging between $4 to $6 per mcf for the foreseeable future.

“My experience tells me most operators need $5-plus gas and even $6 to make a profit,” Peterson said.

Encana, Canada’s largest natural gas producer, has taken a lead in finding growth markets for future production, working with groups in the United States and Canada to present a case of more gas consumption in the power and transportation sectors.
Howard said there is a growth opportunity for gas-fired power in Ontario, where the shift to renewables such as wind and solar requires a backup power source such as natural gas (which burns about 50 per cent cleaner than coal). But he doubts the shift will be widespread across North America.

“Coal is here to stay,” he said.

Mike Dawson, president of CSUG, agreed that finding new markets is critical.

One hopeful development is plans by Kitimat LNG to spend $3 billion to develop an export terminal to send liquefied natural gas (LNG) from the Port of Kitimat, British Columbia, to Asian gas markets. Apache Canada recently agreed to acquire a 51 per cent interest in the project, in which the state-owned Korea National Oil Company also plans to invest. That company also recently announced plans to invest US$1.1 billion to jointly develop Canadian gas fields with Encana.

Dawson said the use of horizontal drilling and multi-stage fracturing to unlock shale gas plays has fundamentally altered the natural gas business in North America.

“There’s strong confidence the gas is there, so the risk profile is changed from geology to engineering,” he said. “It becomes a manufacturing process and you have to be a low-cost operator.”

Dawson isn’t ready to write off juniors.

“But they’ll have to redefine their business model,” to survive in a world of permanently lower gas prices, he said.

However, the National Energy Board (NEB), Canada’s main energy industry regulator and forecaster, isn’t quite as pessimistic.

Paul Mortensen, technical leader for hydrocarbon resources at the Calgary-based agency, said there’s no doubt shale gas has been a “game-changer,” but the NEB believes it’s too soon to assume prices will stay low for many years.

He said the NEB now expects gas prices to average about $5.50 per mcf this year, rising to $6 in 2011 and $6.75 in 2012.

But the trend is not Canada’s friend, as exports of natural gas to the United States continue to decline.

In 2009, for instance, gas exports dropped by almost 11 per cent, caused by falling demand because of the recession and growing U.S. supplies. The NEB recently forecast total Canadian production—down to 14.4 bcf per day in 2009 from 15.8 bcf daily in 2008—will decline to 13.04 bcf per day by 2012.

The impact on the drilling sector of the decline in gas production has been devastating, Mortensen said.

“We’re calling for 4,800 gas wells to be drilled in 2010. [In 2009, 4,000 were drilled],” he said.

The all-time high for wells drilled in Canada was in 2005, when 25,000 were punched. In 2009, one of the worst years in recent history for the drilling sector in Canada, only 8,400 wells were drilled across the country.

The Petroleum Services Association of Canada recently predicted there will be 11,250 oil and gas wells drilled in Canada this year, up from an earlier forecast of 8,000.

The shift to unconventional gas has meant wells are costlier to drill and take longer (an average of nine days, as opposed to less than six in the past per well).

Despite the shift to unconventional gas, shale gas wells are still only a small percentage of the total. For instance, of the 4,000 gas wells drilled last year only 300 were in the Montney basin, the hottest shale gas play. In total, less than 500 mmcf of shale gas was produced last year in Canada.

“It will be a long time before unconventional gas matches production from conventional gas areas,” said Mortensen.

In the United States, where 56 bcf of gas a day was produced last year, only 8.7 bcf came from shale gas plays.

However, the share of shale and tight gas production will rise over time to crowd out conventional production, he said.

A similar trend towards unconventional oil production is occurring in Canada, he said.

By 2020, the oilsands share of total Canadian production is expected to double, from about 40 per cent now to 80 per cent, reaching about 2.8 million to 2.9 million barrels per day.

However, oilsands production could be much higher than that, depending on economic and other factors, he said.

“The trend towards more unconventional production [of both oil and gas] will be gradual,” said Mortensen.

And although natural gas producers face challenging times, especially with accessing U.S. markets, he said Canadian crude and liquids will continue to maintain and even grow its market share, especially as more oilsands crude is brought on. Canadian crudes and liquids are already responsible for about 2.49 million bbl per day of the 11.1 million bbl per day imported by the United States, according to the U.S. Energy Information Administration.

Could a BP Happen Here?

2010-09-23T16:28:00.000-07:00

Could an environmental disaster on a scale similar to BP’s Gulf of Mexico oil spill happen here? A spokesperson for the Energy Resources Conservation Board (ERCB), Alberta's chief energy industry regulator, argues that it's very unlikely.

"The short answer is that it couldn’t happen on land because the logistical difficulties that exist with a deepwater spill simply aren’t in play," says Bob Curran. "[Also] there really aren’t any wells in Alberta that are comparable to the wells they are drilling in the Gulf."

Well, yes, there is that little thing about the lack of an ocean in the province.

And, as Curran alludes to, giant oil finds on the scale of the BP well — U.S. government scientists estimate that between 35,000 and 60,000 barrels a day are leaking into the Gulf — just don't occur any longer in Alberta’s mature basin, where the size of oil discoveries is smaller.

But that doesn't mean Albertans should be complacent and assume the province is immune from environmental disasters.

Just ask Gerry DeSorcy.

DeSorcy, a regulatory consultant with more than 45 years of experience, 38 of those with the Alberta Energy and Utilities Board (now realigned as the Energy Resources Conservation Board and the Alberta Utilities Commission, which separately oversee the oil and gas and utility sectors, respectively), says it's basically a matter of scale.

"The setting is very different [because there is no deep ocean oil extraction in Alberta] and wells producing 25,000 or 40,000 barrels per day just don't exist in the province," says DeSorcy, who was the former chairman and chief executive officer of the province's top energy regulator. "But it's startling to hear politicians and others say it couldn't happen here. It could."

But the "it" would be different.

"It's not a case of a reservoir running wild," he says.

However, environmental disasters are possible in the oilsands, he says.

"There could be a pipeline break there,” says DeSorcy. “Also there could be a structural failure of a dike or a dam up there [that contains the tailings ponds]. It's conceivable there could be some stored [petroleum] product getting into a body of water in the oilsands."

Another possibility is sour gas escaping from a gas well, something that has occurred in the past on a large scale in Alberta.

The most infamous case of sour gas leakage occurred in the Lodgepole area, about 130 kilometres southwest of Edmonton. In 1982, two workers were killed at a wellsite there, and 280,000 tonnes of tonnes of sour gas were spewed into the air.

"The potential for a sour gas leak is greater than for oil," DeSorcy notes. "A sour gas well leak would emit H2S [hydrogen sulphide gas], which is dangerous to the public."

However, he says the ERCB has implemented strict standards for sour gas wells, including a requirement that operators install blowout prevention equipment and have planning in place to respond to a leak, including igniting the gas and rendering it relatively harmless.

Oil and gas companies co-operate to ensure they have enough equipment to respond to spills and other potential environmental problems, he adds, which should provide the public with a degree of confidence.

Response times

Bob Dunbar, an oilsands industry consultant who spent 10 years with the ERCB as the manager of its oilsands department, followed by 12 years with Petro-Canada, says it's unlikely there will be a major environmental disaster in the oilsands.

He says the most likely place for a serious spill would be in the case of pipelines crossing the Athabasca River. Both Syncrude Canada and Suncor Energy have pipelines crossing the waterway, both moving "significant volumes" of oil.

"But in those cases the pipeline operators have shut-off valves that could be closed that would isolate the spill almost instantaneously," he says.

Dunbar also believes operators and regulators can respond quickly to a sour gas leak.

"On average there have been 10,000 wells drilled a year in Alberta, but I think effective regulations have been developed over that time and, the fact is, drilling on land is less technologically complex than drilling in the ocean," he explains.

Adam Driedzic, staff counsel for the Edmonton-based Environmental Law Centre, which helps the public deal with environmental issues, says the BP disaster has caused him to review the issue of energy industry–caused disasters.

He says he worries about industry and government response to a disaster, and about compensation for those harmed. His concern about the response to disasters stems from where most energy projects are located — rural areas.

Rural areas usually have volunteer fire departments and very little other equipment or trained manpower to respond to accidents or environmental disasters. Driedzic says industry should be required to provide emergency response capacity.

He also believes the legal system in Canada puts individuals affected by bad environmental practices by industry at a distinct disadvantage.

"Individuals would have to use tort law, under which it's very difficult to establish negligence in the case of harm to property or people," Driedzic explains.

In the U.S. it is much easier for individuals to establish the liability of corporations.

Because of this it's very unlikely there will ever be an Alberta version of Erin Brockovich, who was played by Julia Roberts in a 2000 film. Brockovich was the legal assistant who helped cancer-plagued residents living near a lake polluted by a California utility company gain millions of dollars in compensation.

Energize Alberta Quiz
Copyright © 2010 Energize Alberta. All Rights Reserved.

2010-09-23T16:25:00.001-07:00

Welcome Praise
Alberta's oilsands are the target of misguided and ill-informed criticism, so a vote of confidence from south of the border is a welcome diversion indeed

There's always something to complain about. To squawk about. To hold up to the spotlight of public scrutiny. To demand be halted, lest the very planet implode under the weight of unsustainable development.

This year - well, most years, actually - it's oil, whether spewing uncontrolled from a deadly drilling accident in the Gulf of Mexico, or being mined from oilsands deposits in northeastern Alberta. The global oil and gas industry has been a target of environmentalists and globalization critics for as long as I can remember, and will continue as a target long after I'm gone, long after Tony Hayward is gone, long after Macondo is finally capped, perhaps long after the last cubic yard of oil-soaked sand is mined, in a hundred years, or a thousand years.

That seems to be the nature of environmentalists and anti-globalization kooks. As a group (some are less intractable than others, I'll admit) they share an inability to stare reality in the face and accept one key fact: today's economy is built on the global production and trade of hydrocarbons. Denying either of these realities would send us spinning back to the dark ages, our transportation anchored by the horse and buggy; our economy dependent on bartering for food; our lives a day-to-day struggle to eat, to survive.
Apropos Alberta's oilsands, the squawk de jour is the "dirtiness" of mined bitumen, as if coal dust, black lung disease, methane explosions, mine collapses, rig explosions and 11 deaths represent some sort of clean-energy nirvana. The facts - the greens and the anti-globalization kooks somehow always manage to conveniently forget the facts, unless they suit their purpose or can be statistically twisted to underpin their own agendas - are that oil from the oilsands is essentially no dirtier, nor any cleaner, than oil produced from the Gulf of Mexico, from the steppes of Russia, from the frozen north or from the jungles of Sumatra. It ain't exactly clean, but it's what our economy is built on, and it ain't going away anytime soon. Not in my lifetime at least.
One of the truths that the greens and the kooks forget is that the oilsands industry - like the broader Canadian oil and gas industry - has a social conscience, and applies this conscience on a daily basis. Far from taking the money and running, oilsands producers in Canada provide support and leadership in everything from infrastructure development (bitumen bucks are key ingredients in highway improvements in the Fort McMurray area) to health care and community-use facilities in every region in which they operate.
Another truth is that Canada's oilsands producers are a lot greener than they get credit for, a fact brought to our attention in July when legislators from the United States - recent targets for environmentalist propaganda about dirty oil - returned from a tour of the oilsands raving about the environmental progress and leadership being shown by major producers there.
Oregon state representative Mike Schaufler returned from his tour more comfortable with Alberta's role in meeting future U.S. energy security needs, despite efforts by environmentalists to tar the oilsands with the "dirty oil" brush.
"I am more comfortable buying oil from Alberta, which shares similar environmental goals with the U.S., than from foreign sources," he said.
While that may seem faint praise, Alberta's oilsands producers haven't received much in the way of kind words from the outside lately. They'll take them when they come, just as they take the criticism and push ahead, doggedly helping to secure North America's energy future.
--Dale Lunan

Drilling Rig Utilization Back to 2007/2008 Levels

2010-09-10T17:07:00.000-07:00

With the fleet size down to its smallest size since 2006 and a 66% jump in the active count from the depths of 2009, drilling rig utilization rates in Western Canada this year are back to levels experienced in 2007 and 2008, Rig Locator records show.
Weekly surveys show an average of 348 rigs were at work over the first eight months of this year, up 66% from 210 active rigs for the same period in 2009. Despite the gain, the active rig count in 2010 is still the third lowest since 2000 topping only the 2009 and 2002 counts.
With the available fleet in western Canada down to 802 units, utilization has surged this year to 43% of the fleet compared to 25% a year ago and utilization rates of 45% in 2008 and 42% in 2007. The peak drilling activity years of 2005 and 2006 (when the fleet was smaller than this year) saw utilization rates of 65% and 67%, respectively.

By far the biggest activity increases this year are in the more oily provinces of Alberta, Saskatchewan and Manitoba as natural gas prices and drilling remains weak compared to prior years.
Alberta’s active rig count between January and the end of August averaged 214 units, up 73% from a year ago but still below all other years since the year 2000.
Saskatchewan’s active rig count is the highest since 1997 with an average of 64 rigs employed by operators to the end of August, up from only 32 a year earlier. And Manitoba is enjoying a mini-boom this year with a record nine rigs at work over the first eight months (including 18 rigs on the go in recent weeks).
British Columbia’s gas and oil fields are seeing a solid year of activity, as good or better than in all years except the gas drilling boom years of 2004 through 2006. An average of 61 rigs have been at work in the province to the end of August, a 22% rise from 50 rigs at work last year.

As of Aug. 31, 411 drilling rigs were at work, representing 51% of the available fleet. That is 203 more rigs active than at the end of August last year. But for shallower capacity rigs (less than 1 850 metres capacity), only 62 of 158 available units were at work this week – a 28% utilization rate.
Yesterday, 259 rigs were at work in Alberta, 126 of them targeting oil or bitumen projects and 117 targeting natural gas or coalbed methane.
--Nickles Energy Group

Bang for the Buck

2010-09-06T10:17:00.000-07:00

Delivering bang for the bucks

In a recovery mode, executive pay is more critical than ever, for executives and shareholders

We’ve all heard or used the expression “That’s what they pay you (or me) the big bucks for!”

Most of the time, it’s a throwaway line, intended to illustrate that someone is doing the unpleasant stuff that needs to be done, that someone is taking care of the little details while looking at the big picture.

But lately, it’s become a phrase that cuts a little closer to home, and not only are people giving voice to it, they’re wanting some backstory too. It’s no longer enough to claim the big bucks—shareholders want to know that you’re earning the big bucks; boards of directors want to know the same thing, and also that you’ll be around next year and the year after and the year after—barring some sort of ill-timed falling out.

In western Canada, the common consensus—among outsiders at least—is that executives of oil and gas companies are a fat and sassy lot, pulling down exorbitant salaries, sitting on lucrative stock options, coasting towards retirement on pension plans that seem more like budgets for small central American dictatorships.

The truth is that oil and gas executives ARE well paid: the top two executives on the leadership team at Canadian Natural Resources—chairman Allan P. Markin and president Steve W. Laut—for example, pulled down a cool $20.6 million between them last year, what with base salary (Markin received none, Laut about $550,00), options worth about $5.9 million each, and non-equity incentive bonuses of $3.5 million each.

And who’s to say that level of pay wasn’t earned? Last year, Canadian Natural solidified its ranking as Canada’s largest oil and gas producer, according to Oilweek’s Top 100 report, with production of 499,300 barrels of oil equivalent per day, up from 489,159 barrels of oil equivalent per day in 2008. Most of that was because of its Horizon oilsands project near Fort McMurray, Alberta.

That kind of performance was attractive to investors, and the company’s stock—a key measure in most executive compensation plans—responded accordingly, rising from a low in 2009 of $36.54 a share on Feb. 23 to a high of more than $78 a share on Oct. 15, before ending the year at an even $76. That’s the kind of share performance most executive teams would give their right arms for, and I’m not sure anyone can begrudge Mr. Markin and Mr. Laut being rewarded for their efforts.

But in the Canadian corporate constellation—never mind the global universe—oil and gas executives fall about the middle of the pack: Markin and Laut represent the top end of the scale, followed closely by Crescent Point Energy (heard of it, have you?) president Scott Saxberg (a member, incidentally, of Oilweek’s inaugural class of Rising Stars in 2008) at about $8.5 million, but the average compensation for the executives we tracked falls in at around the $1.3-million mark. In 2008, Canadian executives overall averaged about $7 million in compensation, so our oil and gas executives don’t exactly fit the stereotype of fat and sassy oil barons sitting on mountains of cash.

They do, however, fit the stereotype of hard-working, imaginative, and focused entrepreneurs, dedicated to building wealth for their shareholders and energy security for the rest of us. They deserve to be congratulated.

--Dale Lunan

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